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DATE

Thursday, April 30, 2026 at 11 a.m. ET

CALL PARTICIPANTS

  • Chief Executive Officer — Michael N. Kennedy
  • Senior Vice President, Liquids Marketing and Transportation — David A. Cannelongo
  • Senior Vice President, Natural Gas Marketing — Justin B. Fowler
  • Chief Financial Officer — Brendan E. Krueger
  • Vice President, Investor Relations — Dan Katzenberg

TAKEAWAYS

  • Production -- Record 3.9 Bcfe per day, up 13%, with full-year guidance of 4.1 Bcfe per day representing nearly 20% growth.
  • Free Cash Flow -- $657 million generated, exceeding the targeted $500 million for the HG acquisition funding window by $250 million.
  • Operating Synergies -- $15 million to $20 million achieved to date from HG integration; full-year forecast raised to over $80 million, above the initial $50 million target.
  • HG Acquisition Scale and Inventory -- Nearly 400,000 net acres and 400 drilling locations added to the core position; integration is ahead of schedule.
  • Cost Structure Improvements -- Anticipated $0.30 per Mcfe decrease in corporate cash costs due to HG acquisition, supporting margin enhancement.
  • Leverage Target -- Leverage of 1.0x is now expected by mid-2026, six months ahead of prior guidance.
  • Natural Gas Hedging -- Over 60% hedged for 2026 and one-third for 2027; liquids remain fully unhedged.
  • LNG Exposure -- Antero Resources Corporation sells 2.3 Bcf per day to LNG sales points, the highest exposure among Appalachian producers.
  • NGL Export Leadership -- Largest U.S. producer-exporter of NGLs, with the majority of LPG volumes sold internationally.
  • NGL Pricing Leverage -- Realized pricing for C3+ improved by approximately $12 per barrel, converting to over $550 million incremental free cash flow.
  • Cash Cost Guidance -- 2026 guidance reduced by $0.10 per Mcfe at midpoint, with Q2–Q4 expense reductions of $0.26 per Mcfe, and broad-based margin expansion initiatives cited.
  • Capital Allocation -- CapEx guidance remains $1 billion, with flexibility to incrementally increase by $200 million, highly discretionary, and subject to commodity pricing trends.
  • HG Efficiency Metrics -- Drilling cycle times cut to under nine days per well from prior three to four times higher averages; completions efficiency leads to faster pad delivery and cost savings.
  • Requests for Gas Supply -- Over 5 Bcf per day of inbound regional proposals for new power projects and data centers, excluding LNG.
  • Post-Acquisition Debt Reduction -- Over $750 million free cash flow used since December to pay down more than 25% of HG acquisition cost; more than half the transaction funded, including Utica divestiture proceeds.
  • NGL Realization Premium -- $0.94 per barrel premium to Mont Belvieu for C3+ achieved in the quarter, with ethane breakout now included for transparency.
  • LPG Export Capacity -- U.S. dock expansions lifted output by up to 610,000 barrels per day to 3 million barrels/day, with another 1 million barrels/day coming by 2028.
  • Regional Power Demand Pipeline -- Cumulative over 8 Bcf per day in announced Appalachian power project demand; West Virginia’s 50 by 50 plan to boost state generation to 50 GW by 2050 supports long-term demand.

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RISKS

  • Senior Vice President Cannelongo said, "At this point in time, there are far too many uncertainties for us to be able to provide updated guidance with a high level of confidence" regarding NGL market impacts stemming from Middle East conflict.
  • Cannelongo said, "we really do not have the inventory" to backfill lost global LPG supply in the MAX export case, underscoring U.S. limitations if Middle East disruptions persist.

SUMMARY

Antero Resources Corporation (AR +0.64%) highlighted the accelerated realization of HG acquisition synergies, with $80 million targeted for 2026 and integration well ahead of plan. The company forecasts leverage of 1.0x by midyear, six months faster than prior guidance, supported by over $750 million in free cash flow since December. LNG and NGL international exposure continues to drive premium realizations, with over 2.3 Bcf per day sold to LNG points and a $0.94 per barrel premium to Mont Belvieu achieved for C3+ NGLs in the quarter—all while liquids remain fully unhedged. Management confirmed more than half of the HG acquisition is already funded, and discretionary capital spending flexibility permits opportunistic pad completions in the second half, contingent on market conditions. The evolving regional power infrastructure, underpinned by data center projects and the West Virginia 50 by 50 plan, sets up incremental demand exceeding 8 Bcf per day, positioning Antero Resources Corporation for expanding sales agreements and improved local pricing amid a tightening basin supply/demand balance.

  • Management said, "we have participated in requests to provide proposals for gas supply that total over 5 Bcf per day," indicating immediate visibility on substantial regional demand outside the LNG channel.
  • No equity was issued to fund the HG acquisition; debt reduction pace is enabling transaction payoff nearly a year ahead of original expectations.
  • High cycle time reductions have contributed to margin improvement, with CEO Kennedy stating, "Drilling as well—we are under nine days per well; they were triple to quadruple that."
  • The 2026 cash cost reduction guidance incorporates $0.07-$0.08 per Mcfe in synergies directly attributed to the HG deal, providing clarity on integration value sources.
  • Recent U.S. LPG dock expansions coincide with rising international demand following Middle East supply reductions, and U.S. propane export volumes reached 2.3 million barrels per day during the reporting week.

INDUSTRY GLOSSARY

  • ARBs: Refers to arbitrage spreads between Mont Belvieu (U.S.), and international LPG pricing benchmarks for spot and term cargoes.
  • Mcfe: Thousand cubic feet equivalent, used to aggregate oil, natural gas, and NGL production volumes for reporting in standardized units.
  • C3+: Industry shorthand for NGL components heavier than ethane (i.e., propane, butane, isobutane, natural gasoline).
  • Mont Belvieu: The primary U.S. pricing hub for NGLs, especially propane and butane, referenced for contract indexation and benchmarking.
  • DUC: Drilled but uncompleted well; reflects inventory that can be rapidly brought online in response to market conditions.
  • LNG Fairway: Physical pipeline and market corridor linking Appalachian production to Gulf Coast and export facilities serving the LNG trade.
  • 50 by 50 Plan: State of West Virginia initiative to increase generating capacity from 15 gigawatts to 50 gigawatts by 2050, fueling increased local demand for natural gas supply.

Full Conference Call Transcript

Michael N. Kennedy: Thank you, Dan. Good morning, everyone. I would like to start my comments by praising our operations team for their success during winter storm Fern. Their ability to achieve 100% uptime on our operations throughout the storm is an impressive achievement. As highlighted on Slide 3, our team’s efforts and strong pricing helped us deliver one of the best quarterly results in company history. Also as highlighted on the slide, we closed on the HG acquisition and the Ohio Utica shale divestiture. The HG acquisition added substantial production, cash flow, and nearly 400 thousand net acres and 400 drilling locations to our core West Virginia Marcellus position.

Importantly, the acquisition will drive corporate cash costs down $0.30 per Mcfe, which lowers our breakeven cost and drives margin enhancement. Turning to the integration of HG, we are significantly ahead of schedule. We recently turned in line our first HG pad. This six-well pad located in the liquids-rich area has 110 thousand total lateral feet, or average lateral lengths over 18 thousand feet per well. Notably, this pad has one of the highest net royalty interests at 89%, further enhancing its rate of return. We expect the pad to produce $150 million per day and remain flat at these levels for quite some time.

On the acquired assets, we have already achieved operating synergies of $15 million to $20 million and are now forecasting over $80 million for the full year, outpacing our initial target of $50 million. Once we closed on the acquisition and took control of operations, we found incremental cost-saving opportunities, which include drilling and completion design changes, water handling optimization, and benefits from our economies of scale that are driving faster-than-forecasted synergies. Our first quarter production was a record 3.9 Bcfe per day, 13% above the year-ago period. This production growth is expected to continue through 2026 with full-year production of 4.1 Bcfe per day, a nearly 20% increase from 2025.

Turning to the right-hand side of the slide, our quarterly financial results were highlighted by our ability to capture substantial premiums to benchmark prices. These high premiums, combined with our operational performance, generated free cash flow of $657 million, the second-highest level in our company history. We used this free cash flow to accelerate debt reduction following the HG acquisition. At the time of the acquisition announcement, we had targeted free cash flow available to fund the acquisition from December through the end of the first quarter to be approximately $500 million. We exceeded this target by $250 million.

Looking ahead, improved NGL fundamentals are expected to result in us hitting our leverage target of 1.0x by mid-2026, six months ahead of prior expectations. Next, let us turn to Slide 4, which highlights our latest hedge position. For 2026, over 60% of our natural gas volumes are hedged, and we have one-third hedged in 2027. Our strategy continues to be targeting a natural gas hedge position of 25% to 50% of annual production, which reduces the volatility in our cash flow and provides an opportunity to be countercyclical in share buybacks or asset acquisition opportunities. On the liquids side, we remain unhedged.

I will close my comments by touching on Antero Resources Corporation’s advantaged position in the base global backdrop, which is highlighted on Slide 5. Recent geopolitical events have highlighted the advantage of Antero Resources Corporation’s corporate strategy. We have the highest LNG exposure among Appalachian producers, selling 2.3 Bcf per day of production to sales points along the LNG fairway. At the same time, we are the largest producer-exporter of NGLs in the U.S., selling the majority of our LPG, which includes propane and butane, into international markets. We expect recent global supply outages and disruptions to lead to increasing risk premiums for U.S. NGL barrels both in the near term and in the years ahead.

These global events are leading to increased demand as international NGL and LNG buyers are looking to de-risk their energy portfolios by diversifying their exposure and increasing purchases of U.S. supply. This shift towards U.S. supply supports higher export utilization and more attractive price premiums at our sales points along the coast. This highlights Antero Resources Corporation’s unique export strategy and positions us well to benefit from today’s rising global demand for U.S. energy. 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 A. Cannelongo, for his comments.

David A. Cannelongo: Thanks, Mike. New market volatility has been introduced to global energy flows, particularly affecting NGL and oil products, with the ongoing conflict in the Middle East following Operation Epiq Fury that began on February 28. We are continually monitoring the Middle East infrastructure attacks, ship transits through the Strait of Hormuz, and assessing the resulting commodity price implications for our business. At this point in time, there are far too many uncertainties for us to be able to provide updated guidance with a high level of confidence. In our opinion, today’s financial market does not yet reflect the most significant supply shock witnessed to date.

However, as the second-largest NGL producer and, as Mike indicated, the largest producer-exporter while also remaining unhedged on NGLs, we are poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing. Focusing in on the impact to the global NGL market, the graph on the left of Slide 6 shows that the Middle East accounted for about 36% of the global waterborne LPG market in 2025. Virtually all of that volume needs to transit the Strait of Hormuz to reach global buyers. The U.S. is the only other major waterborne LPG supplier.

On the demand side, the graph on the right shows the major buyers such as China and India were heavily reliant on the Middle East for supply. These buyers have no other options to replace these barrels except lifting more volume from the U.S. Recent U.S. LPG dock expansions could not have come at a better time, alleviating bottlenecks seen in recent years and making barrels available to global buyers. The U.S. has added up to 610 thousand barrels a day of LPG export capacity over the past year, bringing the total terminal capacity to approximately 3 million barrels a day as illustrated on Slide 7.

Going forward, additional expansions through 2028 will add approximately another 1 million barrels a day of LPG export capacity. The full impact of the recent debottleneck on propane exports has just begun to be realized. Persistent fog in the U.S. Gulf Coast, some mechanical issues, and a relatively higher proportion of butane exports in recent months following the closure of the Strait of Hormuz have kept U.S. propane inventories elevated to start. However, the surplus volume is well positioned to backfill constrained Middle East product as an armada of LPG ships have sailed to the U.S. for their only opportunity to get replacement cargoes.

Notably, we have seen a sharp increase in export volumes in recent weeks, reaching 2.3 million barrels a day of propane alone this week, and we expect record-level exports to sustain in the months ahead. Slide 7 also shows the upside potential for propane exports with the new dock capacity online. The purple dotted line on the chart shows the level of propane exports if terminals were running at or near operational maximums of 90% nameplate capacity. This would represent the U.S. averaging over 400 thousand barrels a day of incremental propane exports in calendar year 2026 over the third-party case published before the conflict, indicating that there is ample room for more propane across U.S. stocks.

Now let us take a closer look at the impact that higher propane exports will have on inventories, which is illustrated on Slide 8. The tan dotted line represents the pre–Epiq Fury inventory outlook from the same third-party provider. At that time, expectations were for propane storage to remain elevated throughout 2026. The blue dotted line presumes that new dock capacity will add an additional 100 thousand barrels a day of exports the remainder of this year to replace a small portion of the LPG supply that has already been lost from the Middle East conflict. Under this scenario, storage would fall below the five-year average by late summer.

The purple dotted line illustrates what happens to U.S. propane storage if dock utilization rates run at 90% for the remainder of 2026. Under this case, we would fall below the five-year range by the early summer and ultimately need a pricing response to keep barrels in the U.S. to avoid a supply shortfall ahead of this upcoming winter. As a reminder, Antero Resources Corporation produces 46 million net barrels of C3+ NGLs; an increase in $1 per barrel of C3+ results in $46 million in incremental cash flows. Antero Resources Corporation’s forecasted realized pricing for C3+ has increased approximately $12 per barrel during this time, reflecting over $550 million of incremental free cash flow in 2026.

Uncertainty remains in the global energy markets from here until there are concrete agreements and realized outcomes in the Middle East. However, U.S. energy supply, and particularly NGLs, remains a consistent supply source to the world in these times of need. With that, I will now turn it over to our Senior Vice President of Natural Gas Marketing, Justin B. Fowler, to discuss the natural gas market.

Justin B. Fowler: Thanks, Dave. I will start on Slide 9 titled Near-Term LNG Capacity Additions. LNG export demand is expected to increase by 7 Bcf per day by 2027. Golden Pass shipped its first cargo last week and is expected to ramp up 1.6 Bcf per day of capacity in 2026, ultimately exporting 2.4 Bcf per day in 2027. This increase in LNG export demand, when combined with higher power demand and increasing exports to Mexico, results in an undersupplied U.S. market over the next two years. This wave of new LNG export capacity is arriving at a much-needed time.

Turning to Slide 10, the EU exited this past winter at the second-lowest storage level on record, falling below 30% at the end of the first quarter. Adding to this storage issue is that EU imports from the Middle East have declined 91% in March and April. Supply outages and disruptions in that region are likely to result in reduced LNG exports throughout 2026. In order to fill storage to the EU’s 80% target ahead of next winter, the EU will need to begin purchasing significant cargoes from the U.S. In Asia, we see a similar position. We expect low storage levels and global supply outages to result in U.S.

LNG utilization rates running above historical levels, drawing down U.S. storage this year and supporting prices as we move into this winter. Now let us turn to regional demand, which is highlighted on Slide 11. The power projects highlighted on this slide are the ones that have been publicly announced in our region to date and amount to over 8 Bcf per day of demand. Based on the conversations we have had, which also include nondisclosed projects, we estimate that regional power demand projects exceed 10 Bcf per day in total.

In just West Virginia in recent weeks, we have had projects announced from a combined data center facility with customers that include Microsoft and NVIDIA, and also separately a project that is tied to Google. Late last year, the state of West Virginia announced its 50 by 50 plan, which is an initiative to increase the state’s power generation capacity from 15 gigawatts today to 50 gigawatts by 2050. Additionally, surrounding states are considering removing tax exemptions for data center facilities that could drive increased opportunities for West Virginia to attract new projects to the state. This incremental 8 Bcf per day of regional demand growth compares to total production in the basin of approximately 36 Bcf per day.

Given the large demand pull from LNG in the coming years, we believe there is only so much gas that producers will be able to commit to long-term deals with these projects. Ultimately, this tightness should provide support in two ways: first, more attractive pricing to producers related to long-term supply deals, and second, improved overall local market pricing as a result. As West Virginia’s largest natural gas producer, with a significant infrastructure footprint through Antero Midstream, we believe we are well positioned to participate in supplying the natural gas that these projects will require. With that, I will turn it over to Brendan E. Krueger, CFO of Antero Resources Corporation.

Brendan E. Krueger: Thanks, Justin. I will start on Slide 12, which highlights our cash cost reductions going forward. We reduced our 2026 cash cost guidance by $0.10 per Mcfe at the midpoint. This reduced range reflects second quarter through fourth quarter 2026 cash production expense reductions of $0.26 per Mcfe, or over 10% below the full-year average in 2025. When we include G&A and net marketing expense, cost reductions totaled $0.30 per Mcfe. Beyond 2026, we see opportunities for further cost reductions and margin enhancement through several initiatives that we plan to discuss in the quarters ahead.

Many of the initiatives relate to our commercial agreements on natural gas and liquids takeaway, as well as taking a more balanced approach to the development of our liquids-rich and dry gas acreage. We see opportunities to lower our overall transport expense and improve our corporate margins through direct agreements with end users, replacing expiring transport with better netback transactions, and simply letting certain contracts that are no longer needed expire. Some of these opportunities will occur in the near future while others will take place over multiple years as contracts come up for renewal.

Speaking further to the regional demand opportunities that Justin discussed, in just the last few months alone, we have participated in requests to provide proposals for gas supply that total over 5 Bcf per day. While it is still undetermined whether we will participate in these projects, we do believe the demand is only growing for natural gas, and particularly natural gas that can be supplied by an investment-grade producer with multiple decades of undeveloped inventory. Moving to Slide 13, I would like to finish my comments by touching on the progress we have made with funding the HG acquisition.

As shown on the chart, we are ahead of initial expectations of paying down the debt associated with this recent transaction. With the help of the exceptional operations performance that Mike touched on, we were able to generate over $750 million of free cash flow from December through the end of this first quarter, which was used to pay down over 25% of the acquisition cost. Combining this with the proceeds from the Utica divestiture, we have already funded over half of the transaction. Based on our next-twelve-months free cash flow at current strip, we expect to have fully funded the transaction by early next year.

This updated payoff timing is nearly a year ahead of what we expected when we announced the acquisition in December. To reiterate what we have said on past calls, after paying off the remainder of the debt associated with the HG acquisition, we will have increased production by more than 700 thousand Mcfe per day equivalent, added 400 undeveloped locations to our core West Virginia Marcellus inventory, and meaningfully reduced our cost structure, which translates into higher sustained free cash flow. Importantly, we accomplished these changes without having to issue a share of AR equity.

At the same time, the overall macro environment for natural gas and NGLs has only strengthened with the current geopolitical environment and continued structural demand growth for both power and U.S. LNG. With that, I will now turn the call over to the operator for questions.

Operator: Thank you. We will now be conducting a question-and-answer session. Our first question is coming from Arun Jayaram from JPMorgan Chase & Co. Your line is now live.

Arun Jayaram: Good morning. Dave, maybe starting with you, I was wondering if you could give us a little bit more color on how your marketing arrangements work regarding your export volumes. I know you printed a $0.94 premium to Mont Belvieu in the first quarter for C3+, but give us a sense of how much international exposure you have to pricing versus Mont Belvieu?

David A. Cannelongo: Yeah, Arun. Good morning. In the first quarter, we had international index pricing in our portfolio and Mont Belvieu as well. We have a portfolio of term and spot transactions. We have been participating in some of the run-up that you saw following Epiq Fury on the ARBs, where you could see April and May. You are not going to sell something in March typically when you are already in March; April is what is trading for a spot cargo. You will see some cargoes that we sold in April and May that were on some of the higher pricing as a result of this. But if you look out even to June, the ARBs have already tightened quite considerably.

They are now in the $0.10 to $0.15 per gallon premium to Mont Belvieu range. As we look forward through the year with the inventory situation and what we expect to happen as the U.S. attempts to meet a portion of what the rest of the world has lost through this conflict in the Middle East, those ARBs will tighten further. It is tough to say for the balance of the year how tight those ARBs will get, but ultimately what we want to see is stronger Mont Belvieu index pricing. That is really what we are the most constructive on.

We think that is really the story of 2026, and we are in a great position to benefit from that, given that we have not hedged any of our NGL volumes.

Michael N. Kennedy: To highlight, we are very conservative when it comes to our guidance. There is a lot of uncertainty like there is today. We are not going to try to capture that in a moment in time. We will just see how it plays out over the year.

Arun Jayaram: You mentioned 2.3 million barrels a day of exports last week, so that is a punchy number. One of your peers did raise their NGL realization guidance. I know they do the entire barrel, not just C3+, up to a $1.25 to $2.50 premium. You maintained your overall guidance. Why maintain rather than raise given you booked a premium in the first quarter?

David A. Cannelongo: Yes, Arun. I would say we did actually raise guidance on the ethane piece, and that is really the story here. It is kind of apples and oranges between us and other producers that include ethane in their NGL pricing. We have always historically broken ethane out for transparency purposes. You can have dramatic swings in the amount of ethane that you recover from quarter to quarter or month to month. It could be local crackers are down as we have seen in prior quarters, or it could be like we had in the first quarter where you have very strong regional gas pricing and you reduce your ethane recoveries as low as you possibly can.

When you lump it all together, what is your benchmark index against? Is it a static fixed percent of ethane as the benchmark? I think that is what you see other producers do. You can end up with a lot of your C3+ barrels getting benchmarked against an ethane price, and that is typically when you see a large beat from a C2+ kind of benchmark producer compared to somebody like us. If you put our ethane into it, we would have had about a $6 premium to Belvieu on a similar benchmark index to other producers. For those reasons, we have historically broken it out for transparency.

Operator: Thank you. Next question today is coming from Kevin McCarthy from Pickering Energy Partners. Your line is now live.

Kevin McCarthy: Thanks for taking my question. I wanted to ask about the cash production expenses. It looks like you lowered them $0.10. How much of that reduction is driven by synergies from the HG acquisition versus lower gas prices?

Brendan E. Krueger: Yes. The majority of that is HG. Lower gas prices were a couple of pennies, but $0.07 to $0.08 of it was HG. We acquired the assets and underwrote very conservative assumptions around our ability to operate the assets and the integration and how quickly we would be able to realize the lower cost, and we are well ahead of those assumptions that we announced earlier. That is why we are comfortable lowering the guidance.

Kevin McCarthy: As a follow-up, on the CapEx budget, in the fourth-quarter earnings release, you talked about the option to spend an extra $200 million of growth capital. In this release, it looks like your official guidance is still at $1 billion. How are you thinking about spending that extra growth CapEx given current prices in gas and NGLs?

Michael N. Kennedy: Yes, Kevin, that is unchanged, still $1 billion with the potential to go to $1.2 billion. The attractiveness of our program is that it is truly incremental capital with no underlying commitments needed. So it is discretionary. It is completing three pads in the second half of the year. That is still to be determined. We get the ability to watch local and natural gas prices, see if the demand is there for it, and see if it is attractive to complete those. That is a second-half event, and we will make the call then with more information around natural gas prices.

Operator: Thank you. Next question is coming from John Freeman from Raymond James. Your line is now live.

John Freeman: Brendan, I want to follow up on what you highlighted that you are looking at 5 Bcf per day of gas supply proposals. Can you speak to the mix between LNG or data center opportunities or otherwise?

Brendan E. Krueger: That was all regional, local demand—not only data centers, but power projects as well. It did not have any LNG in that 5 Bcf per day. Where we see a lot of benefit, and why we are getting a lot of these requests for proposals, is driven by the integrated nature of having both upstream and midstream: Antero Resources Corporation being an investment-grade producer that can supply the gas with significant undeveloped inventory, and Antero Midstream that can build the pipelines to the areas that need it. That is driving a lot of the requests.

John Freeman: Good to see the accelerated free cash flow and ability to pay down the term loan even quicker. If we look ahead to 2027, once the term loan is gone and you just have the 2030 and 2036 paper that is attractively priced and non-callable until 2028, should we assume that nearly all the free cash flow is going toward buybacks?

Michael N. Kennedy: That would be a fair assumption. One of the attractive aspects of our hedge position and our growth and scale is the ability to be countercyclical on buybacks if you see any weakness. Assuming current commodity prices for 2026 and 2027 and the early redemption of that term loan in early 2027, about a year ahead of our initial expectations, a good assumption for 2027 would be share buybacks for the incremental free cash flow.

Operator: Thank you. Next question is coming from Gabe Daoud from Truist. Your line is now live.

Gabe Daoud: Thanks. Curious about expectations for future M&A as some West Virginia acreage and packages could be available. Given HG and how quickly you hit some of the synergies, is there continued appetite for more?

Michael N. Kennedy: We are the dominant energy producer in West Virginia. We produce about half of the natural gas in the state, have close to almost 1 million acres there, and decades’ worth of inventory. We are the West Virginia energy producer. Anything within West Virginia you can assume we would evaluate, and if it is attractive to us, it is something we would be interested in.

Gabe Daoud: Thanks. Could you also highlight how Antero Midstream could be a differentiator on the water side with some of these data centers and hyperscalers?

Michael N. Kennedy: We like to say Antero Midstream is the industrial builder of Northern West Virginia, whether it is gathering for hydrocarbons or water. We have the most extensive water system in the state and really across the country. We are an expert in building water infrastructure, and these projects require substantial water. That is a benefit to us and a strategic advantage for Antero Resources Corporation and Antero Midstream.

Operator: Thank you. The next question is coming from Jacob Roberts from TPH. Your line is now live.

Jacob Roberts: Good morning. Could you remind us where you see the liquids cut progressing through this year? I am curious if you could talk more about the processing cost reduction. Is that solely a function of the higher dry gas volumes, or is there more to the HG story?

Michael N. Kennedy: It does not really move the needle. We are in the low-30s on the liquids cut, and it does not really change from where we are at today. We have one rig right now drilling liquids, one in the blended liquids/dry gas, and one rig in the dry gas on the HG acreage. So a very balanced development profile, and it does not really move the needle from where we are today.

Jacob Roberts: As a follow-up on the recontracting potential, is part of the thinking that you see the potential for a long-term supply agreement with a utility or data center that could help offset some of the FT commitments by way of a supply contract?

Michael N. Kennedy: That is a big story going forward. Our initial story is lowering cost through HG and optimizing our acreage and portfolio, including developing dry gas. On a go-forward basis, a big story around Antero Resources Corporation is the optimization of our transport arrangements. We had to take out the initial takeaway to create this development program in Appalachia in West Virginia, and those agreements are 10 to 15 years old. Going forward, they really need to be in the hands of the end user. We will be able to enter into attractive sales and optimize our margins as we recontract.

Some of the liquids-related contracts very near-term are ones we are not using and just carrying, and you are talking hundreds of millions of dollars of incremental EBITDA to us on an annual basis when these expire.

Jacob Roberts: Is there a counterparty type that seems more amenable to that type of arrangement?

Michael N. Kennedy: They are all amenable. There is very high demand for our product across North America and the world. There is so much demand that counterparties are amenable to being the buyer of our product.

Operator: Thank you. Next question is coming from Josh Silverstein from UBS. Your line is now live.

Josh Silverstein: On the new power capacity coming to the region, on volume and pricing, is this something that you are waiting to see develop and then you can grow supply into it? Do you want to get more exposure to local pricing as well?

Michael N. Kennedy: Exactly. We are attracted to the local demand because it is low cost, with variable transport costs. Realizations could be pretty good. It is all incremental demand too, so we will be able to grow into it. That is part of our low-cost growth strategy.

Josh Silverstein: On the HG acquisition, you highlighted OpEx cost synergies. The biggest piece was development optimization. How is that going, and is that something we will see more benefit from later this year or more in 2027 relative to now?

Michael N. Kennedy: That is definitely the majority of the synergy. A perfect example is completion stages per day. HG was in the 2–4 stages per day range. We average over 14 stages per day. On this pad we just brought on, the prior operator was doing 2–3 stages per day going south; this week we have been doing 11. You can imagine the efficiencies and cycle time optimization that come with that. We did not underwrite that in our acquisition valuation, so that all accrues to our shareholders. Drilling as well—we are under nine days per well; they were triple to quadruple that. Bringing that into the portfolio really brings forward value and drives synergies going forward.

Operator: Thank you. Next question is coming from Neil Mehta from Goldman Sachs. Your line is now live.

Neil Mehta: Slide 7 and 8 on new propane dock capacity and inventory are great. The MAX export case by the summer looks quite extreme. How real is the potential for the MAX export case to play out, and what are the biggest gating factors?

David A. Cannelongo: Neil, this is Dave. The MAX export case is what the world would love to see to try and backfill just a portion of the LPG supply that is lost globally. You are seeing reports about shortages and high canister prices in parts of Central and Southeast Asia already. They would love for the U.S. to try and do the MAX export case. What we were trying to illustrate is we really do not have the inventory to do that. If the war were resolved in the next few weeks and things reopened by June, and the world has lost 120 million barrels or more of LPG, we could probably backfill about 30 million barrels from the U.S.

That is ultimately why we are so constructive on Mont Belvieu propane pricing. Even at the MAX export case, we do not come close to backfilling the loss.

Neil Mehta: On future dock expansions slated for 2026, is everything tracking well?

David A. Cannelongo: Yes. One of the large midstream players has talked about commissioning ongoing, a little ahead of where people had pegged it a few months ago. Year-to-date 2026, things are ahead. Typically, those projects are brought online on time. LPG export capacity is not as complex to build compared to, for example, an LNG facility.

Operator: Thank you. Next question is coming from BMO. Your line is now live.

Analyst: Good morning. Sticking with recent announcements in West Virginia, about a year ago the state signed the microgrids bill to attract data centers. How much has this helped conversations with hyperscalers, and what are other positives that would favor West Virginia versus other states within Appalachia?

Michael N. Kennedy: That has definitely been a help, and we appreciate the microgrid bill. It put West Virginia front and center for these discussions. West Virginia’s advantages are clear: geographically, it is within about 100 miles to the data center alley; it has the water; it has the lowest-cost natural gas and energy; it is near population centers to the east; and it has favorable climate. There was a report noting that all the attributes you look for converge in West Virginia. We are uniquely positioned as we produce over half the state’s natural gas.

Analyst: A couple of quarters ago you included a regional gas demand project list. Monarch was a 2030 startup at 430 thousand Mcf per day. Now it looks bigger and earlier in the first phase. Without updating the slide, are there others that could be pulled forward in timing or increased in magnitude? Of the 8 Bcf per day on Slide 11, how much is under construction or has reached FID?

Michael N. Kennedy: I do not have the exact figure for what is under construction or at FID, but based on conversations we are having, we see the total well ahead of 10 Bcf per day. Many publicly disclosed projects are initial phases. To the extent they continue to build and scale, those numbers will be larger. Some are speeding up. Our view is you really see this start to take hold in 2027–2029 as facilities come online in phases. Monarch is a good example: they have talked about their Phase 1, but that will continue to scale.

The microgrid bill allows phasing within a four-mile halo, so some sites can continue to scale up within that halo and still fall under the bill in West Virginia.

Operator: Our next question today is coming from Leo Mariani from ROTH. Your line is now live.

Leo Mariani: You have been helpful providing the production ramp post-HG with guidance into the second half. Could you talk similarly on capital? Presumably first quarter is a low and CapEx picks up in following quarters, and the optional growth capital would be second half if you decide to spend it.

Brendan E. Krueger: Correct. We have a full contribution for capital in the second quarter for HG, so second, third, and fourth quarters are kind of in the $300 million range, assuming we complete some of those pads we discussed for the growth case. If we do not do that, then it steps back down from $300 million more to the $250 million range in the third and fourth quarters.

Leo Mariani: On the synergies, you talked about the $80 million target. Would you expect that all to be realized in 2026, or can some linger into next year? Is the bulk operating costs and G&A, or is there a capital portion as well?

Brendan E. Krueger: The $80 million is for 2026. That accelerates on a go-forward basis as we continue to improve and integrate the asset into our operations. We have discussed synergies up to $1 billion over time, and we are ahead of that right now. It is $80 million this year and more like $100 million annually after that.

Operator: Thank you. Our next question today is coming from Doug Leggate from Wolfe Research. Your line is now live.

Doug Leggate: Thanks. On Slides 7 and 8, your base case still looks conservative. What would it take for you to change that, given exports are already running at record levels in April?

David A. Cannelongo: It is really a question of how little inventory the U.S. is comfortable having as we enter winter. When you see our base case dipping below the five-year range, you typically see very strong domestic demand to keep barrels onshore for winter. You get a tug-of-war between domestic and international. That is why we did not illustrate a stronger base case. As I said earlier, the world would like us to do the MAX export case; we just do not have enough supply.

Doug Leggate: Is your view on the premium to Mont Belvieu directly related to your view on exports? If exports go up, does your Mont Belvieu premium reset again in the second quarter?

David A. Cannelongo: We think parties selling spot cargoes in the second half of this year will be getting modest premiums to Mont Belvieu, as we have seen when there is ample dock capacity but not enough inventory for both exports and domestic. But you will have higher Mont Belvieu pricing.

Doug Leggate: On data center negotiations, are any of your negotiations exclusive, or are they all being put up to bid? What does the nature of negotiations look like?

Brendan E. Krueger: For most of it, it is a request for proposal to a number of parties. We feel we are well advantaged being an investment-grade producer. To the extent we do not get specific deals but the demand still takes place, it should cause a rise in local prices, which we will benefit from. We are supportive of these projects getting off the ground. There is only so much gas to go around, and ultimately it should drive an increase in local pricing, which will benefit us.

Operator: Thank you. Next question today is coming from Paul Diamond from Citi. Your line is now live.

Paul Diamond: Thanks. Sticking on the AI and power contracts, we have seen variability in terms and structure. Is there an emerging structure that is most common, or is it highly variable based on end market needs?

Brendan E. Krueger: It depends on where the supply is coming from. Some deals we are looking at would be supplied off of our firm transport. Pricing for that may be different than if Antero Midstream is building in-state pipeline to supply a gas deal. Depending on the deal, the pricing could change. Many counterparties see what we talked about: there is 5 Bcf per day of demand, and we obviously cannot supply all of that. They are getting more nervous about where supply will come from, which should drive better pricing on these deals and a rise in local pricing. It could take a local market index or be tied to Henry Hub—still up in the air.

Paul Diamond: On the balance between gas and liquids on a medium-term basis, is that normal-cycle reactivity, or building DUCs for short-cycle response? How do you see that playing out?

Michael N. Kennedy: It is a bit of both. What is really driving it is a more balanced approach. We just put on our first dry gas pad in over a decade, and it is exceeding expectations. We have over 1,000 locations in the premium core of the Marcellus dry gas, and we need to develop that. Having it coincide with local demand will really drive one rig there for the foreseeable future, with one rig in the liquids and one on HG that can flex between dry gas and liquids. It is a blended, balanced plan to lower our cost structure, drive low-cost growth, optimize margins, and grow EBITDA. We need to tap into that legacy acreage and develop it.

Paul Diamond: Do you see value in building a large DUC inventory, or do you like your current structure?

Michael N. Kennedy: We do not see a large DUC inventory. We are talking about three pads right now, maybe entering 2027 with three DUC pads. That will be the call we make in the second half based on local natural gas prices.

Operator: We have reached the end of our question-and-answer session. I would like to turn the floor back over to management for any further or closing comments.

Dan Katzenberg: I would like to thank everybody for joining us on the first quarter 2026 conference call. Please feel free to reach out with any further questions.

Operator: Thank you. That does conclude today’s teleconference and webcast. You may disconnect at this time and have a wonderful day. We thank you for your participation today.