Antero Resources Corporation (NYSE:AR) Q1 2026 Earnings Call Transcript

Antero Resources Corporation (NYSE:AR) Q1 2026 Earnings Call Transcript April 30, 2026

Operator: Greetings, and welcome to the Antero Resources Corporation First Quarter 2026 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded. [Operator Instructions] 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’s First Quarter 2026 Investor Conference Call. We’ll spend a few minutes going through the financial and operating highlights, and then we’ll open it up for Q&A. . 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 our earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Michael Kennedy: Thank you, Dan, and good morning, everyone. I’d 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 in the Ohio Utica Shale divestiture. The HG acquisition added substantial production cash flow in nearly 400,000 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 costs 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. The 6-well pad located in the liquids-rich area has 110,000 total lateral feet or average lateral lengths over 18,000 feet per well. Notably, this pad has one of the highest net royalty interest 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 terrific operational performance, generated free cash flow of $657 million, the second highest level in our company history. We use 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 1x by mid-2026, 6 months ahead of prior expectations. Next, let’s turn to Slide #4, which highlights our latest hedge position. For 2026, over 60% of our natural gas volumes are hedged and we have 1/3 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’ll close my comments today by touching on Antero’s advantaged position in today’s global backdrop, which is highlighted on Slide #5.

The recent geopolitical events have highlighted the advantage of Antero’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 from international NGL and LNG buyers that are looking to derisk 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’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’m going to turn it over to our Senior Vice President of Liquids Marketing and Transportation. Dave Cannelongo go for his comments.

David 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 Epic 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 witness 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 and 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 in the U.S. Recent U.S. LPG dock expansions couldn’t 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 610,000 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 are running at or near operational maximums of 90% nameplate capacity. This would represent the U.S. averaging of over 400,000 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’s take a closer look at the impact that higher propane exports will have on inventories, which is illustrated on Slide #8. The TAM dotted line represents the pre-Epic 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 100,000 barrels a day of exports for the remainder of this year to replace a small portion of the LPG supply that has already been lost from the Middle East Complex. Under the scenario, storage would fall below the 5-year average by late summer. The purple dotted line illustrates what happens to U.S. propane storage at dock utilization rates run at 90% for the remainder of 2026. Under this case, we would fall below the 5-year range by the early summer and ultimately need a pricing response to keep barrels in the U.S. to avoid supply shortfall ahead of this upcoming winter. As a reminder, Antero produces 46 million net barrels of C3+ NGLs, so an increase of $1 per barrel of C3+ results in $46 million in incremental cash flows.

Antero’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 remain a consistent supply source to the world in these times of need. With that, I’ll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler to discuss the natural gas market.

Justin B. Fowler: Thanks, Dave. I’ll start on Slide #9 titled Near-tErm LNG Capacity Additions. LNG export demand is expected to increase by 7 Bcf per day by the end of 2027. Golden Pass shipped its first cargo last week and is expected to ramp up with 1.6 Bcf 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 2 years. This wave of new LNG export capacity is arriving at a much needed time. Turning to Slide #10. Let’s take a look at the current European storage. 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 the storage issue is the 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. and Asia is also in a similar position. We expect low storage levels and global supply outages 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’s 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. Also separately, a project that is tied to Google. Late last year, the state of West Virginia announced its 50 x 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 a 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 2 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 Krueger, CFO of Antero Resources.

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Brendan Krueger: Thanks, Justin. I’ll 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 a 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’d 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 of last year 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 12 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 million cubic feet a 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 from both power and U.S. LNG.

With that, I will now turn the call over to the operator for questions. .

Q&A Session

Operator: [Operator Instructions] Our first question is coming from Arun Jayaram from JPMorgan Chase & Co.

Arun Jayaram: Dan, maybe starting with you, I was wondering if you could just 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 1Q for C3+. But give us a little bit of sense of how much international exposure you have to pricing versus Mont Belvieu?

David Cannelongo: Yes, Arun, we did in the first quarter, we had international index pricing in our portfolio. We had Mont Belvieu as well. We have a portfolio of term as well as spot transactions. So we’ve been participating in some of the run-up that you saw really was following up Epic Fury on the [indiscernible] where you could see April and May, you’re not going to sell something in March, typically, when you’re already in the first week of March, April is what’s trading for a spot cargo. So you’ll 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 the June, the arbs have already tightened quite considerably, they’re now in the $0.10 to $0.15 per gallon premium to Mont Belvieu range.

And I think as we look out forward in the year with the inventory situation and what we expect to happen just 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. So tough to say balance of the year, how tight those arbs will get. But ultimately, that’s what we want to see that stronger Mont Belvieu index pricing. That’s really what we’re the most constructive on. We think that’s really the story of 2026, and we’re in a great position to benefit from that, just given that we have not hedged any of our NGL volumes. So we’ll see where that goes.

Arun Jayaram: Yes, you mentioned 2.3 million barrels of exports last week. So that’s a punchy number. Dave, maybe not to pick on you, but one of your peers did raise their NGL realization guidance. I know they do the entire barrel, not just C3+ to, call it, [ 125 to 250 ] premium. That’s not to quibble on that, but you maintained your overall guidance. I was wondering if you could just give us some thoughts around that the maintenance of your guidance and not a raise, given you did book a little bit of a premium in 1Q?

David Cannelongo: Yes, Arun, I would say we did actually raise guidance on the ethane piece, and that’s really maybe the story here to talk about. So I think that’s the main — kind of apples and oranges between us and other producers that include ethane in their NGL pricing. We’ve always historically broken out for transparency purposes. And the reason is really that you can have dramatic swings in the amount of ethane that you recover from quarter-to-quarter, month-to-month could be local crackers were down as we’ve seen in prior quarters or it could be like we have here in the first quarter where you have very, very strong regional gas pricing and you reduce your ethane recoveries as low as you possibly can. Well, when you’re doing that and you’re lumping it all together, what’s your benchmark index against?

Is it a static fixed percent of ethane as the — in the benchmark. And I think that’s what you see other producers do. So you get into a situation where you actually can end up with a lot of your C3+ barrels getting benchmarked against an ethane price. And that’s typically when you see a large beat from a C2+ kind of benchmark producer compared to somebody like us. I think if you put our ethane into it, we would have had a $6 premium to Belvieu on a similar benchmark index to other producers. So for those reasons alone, we just historically have always broken it out for transparency purposes.

Michael Kennedy: I’d also add to that detailed explanation. Yes, I’ll highlight. We’re very conservative when it comes to our guidance. There’s a lot of uncertainty like there is today. We’re not going to try to capture that in a moment in time, we’ll just see how it plays out over the year.

Operator: Next question today is coming from Kevin MacCurdy from Pickering Energy Partners.

Kevin MacCurdy: I wanted to ask about the cash production expenses. It looks like you lowered them $0.10. Just maybe for some clarification. How much of that reduction is driven by synergies from the HG acquisition versus just maybe lower gas prices?

Michael Kennedy: Yes. The majority of [indiscernible]. Lower gas prices were a couple of pennies of that, but $0.07 or $0.08 of that was HG. When we acquired the assets, we underwrote very conservative assumptions around our ability to operate the assets and the integration and how quickly we’d be able to realize the lower costs, and we’re well ahead of those assumptions that we announced earlier. So that’s why we’re comfortable lowering the guidance.

Kevin MacCurdy: Great. And maybe as a follow-up, looking for some clarification on the CapEx budget. In the 4Q earnings release, you guys talked about the opportunity or 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. Just maybe curious how you’re thinking about spending that extra growth CapEx given the current prices in gas and NGLs?

Michael Kennedy: Yes, Kevin, that’s unchanged, still $1 billion with the potential to go to $1.2 billion. I think the attractiveness of our program is that’s truly incremental capital with no underlying commitments needed. So it is discretionary. It’s completing 3 pads in the second half of the year. So that’s still TBD. So we get the ability to watch local and natural gas prices, see if the demand’s there for it, see if it’s attractive to complete those. So that’s a second half event, and we’ll be able to make the call then with more information around the natural gas prices.

Operator: Next question is coming from John Freeman from Raymond James.

John Freeman: Brendan, I wanted to follow up on what you highlighted that you all are, I guess, evaluating and looking at 5 Bs a day of very sort of gas supply arrangements. Can you speak to sort of the mix of those between sort of like LNG or data center opportunities or otherwise?

Michael Kennedy: Probably that was all regional, local demand, not only data centers but power projects as well as didn’t have any LNG in that 5 Bcf.

Brendan Krueger: Yes, I think where we see a lot of the benefit why we’re getting a lot of these requests for proposals on this, it’s just driven by the integrated nature of having both upstream and midstream, AR being an investment-grade producer that can supply to gas and significant undeveloped inventory at AM that can build the pipelines to the areas that need it. So I think that’s what’s driving a lot of the requests.

John Freeman: Got it. And then obviously, good to see the accelerated free cash flow ability to pay down that term loan even quicker. I know you all are going to try to be opportunistic, but obviously, it looks like the main focus has taken majority of the free cash flow, vast majority and taking out that term loan by the start of ’27. If we look ahead to ’27, am I thinking about it right that once the term loan is gone and you just have basically that 2030, 2036 paper that’s, a, very attractively priced, and I think can’t even — neither of it can recall until like 2028. Should we just assume once we get to that point where the term loan has gone, nearly all the free cash flow is going towards buybacks?

Michael Kennedy: That would be a fair assumption right now. one of the attractiveness of our hedge position and our growth and our scale is the ability to be countercyclical on buybacks. So you do see any weakness, we’ll be there for that time frame. But assuming current commodity price — current commodity for ’26 and ’27 and the early redemption of that term loan by early ’27 about a year ahead of our initial expectations, I think a good assumption for ’27 would be share buybacks for the incremental free cash flow.

Operator: Next question is coming from [indiscernible] from Truist.

Unknown Analyst: Maybe just curious around expectations for future M&A as maybe some additional West Virginia acreage and packages that could be available. So just curious, given HG and how quickly you kind of hit some of the synergies if there’s continued appetite for more.

Michael Kennedy: Yes. We are the dominant energy producer in West Virginia, produce about half of the natural gas in the states, have close to almost 1 million acres there and decades worth of inventory. And so we are the West Virginia energy producer. And I think within West Virginia, you would assume that we would evaluate and if it’s attractive to us, it would be something we’d be interested in.

Unknown Analyst: Got it. Got it. Okay. That’s helpful. And then I guess just as a quick follow-up. You noted this in the past in AM, obviously, providing some additional benefits and conversations with gas deals. But could you also maybe just highlight or talk about how AM could prove to be a differentiator on the water side with some of these data centers and hyperscalers?

Michael Kennedy: Yes. We always like to say AM is the industrial builder of Northern West Virginia, whether it’s gathering for hydrocarbons or water, we do have the most extensive water system in the state and really across the country. So we are an expert in building water and all of these projects do require substantial water needs. So that is a benefit to us and a strategic advantage for AR and AM.

Operator: Next question is coming from Jacob Roberts from TPH.

Jacob Roberts: could you remind us of where you see the liquids cut progressing through this year? And really, I’m 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 H2 story that we’re not seeing?

Michael Kennedy: No. Like you said, it doesn’t really move the needle. I think it’s like 30-70. What’s the exact? Brendan said…

Brendan Krueger: Low 30s.

Michael Kennedy: Low 30s on the liquids and it doesn’t really move the needle. We’ve got 1 rig right now drillings liquids, one in kind of the blended like liquid [indiscernible] dry gas and 1 rig in the dry gas on the HG acreage. So very balanced profile for development, and it really doesn’t move the needle from where we’re at today..

Jacob Roberts: Okay. Perfect. And if I could follow up on that comment about some of the recontracting potential coming up. Is part of that thinking that you see the potential for a long-term supply agreement with a utility or data center or something like that, that could help offset some of the FT commitments by way of a supply contract.

Michael Kennedy: Yes. I think that’s — it’s a big story going forward. I mean our initial story is lowering the cost for the HD developing dry gas and optimizing our acreage and portfolio. On a go-forward basis, it’s a big story around Antero, the optimization of all our transport arrangements. We had to take out the initial FT. We created this development program in Appalachia and West Virginia, we needed to underwrite all the takeaway, but those agreements are 10, 15 years old and so now going forward, they really need to be in the hands of the end user and we’ll be able to entering the pretty really attractive sales and optimize our margins on a go-forward basis, and we recontract that. Some of them around some liquids very near term are actually ones we’re not using it, just carrying and you’re talking hundreds of millions of dollars of incremental EBITDA to us on an annual basis when these expire.

Jacob Roberts: Great. If I could tack one more on, is there a counterparty type that seems more amenable to that type of arrangement?

Michael Kennedy: They’re all amenable to it. There’s very much high demand for our product, haven’t noticed across North America and the world. So there’s so much demand for our product that they’re all amenable to being the buyer of our product.

Operator: Next question is coming from Josh Silverstein with UBS.

Joshua Silverstein: Just on the new power capacity coming to the region, I am curious just maybe on the volume and maybe pricing side. Is this something that you’re kind of waiting around to see develop and then you can grow supply into this? And then do you want to get more pricing exposure to local pricing as well. I mean I’m assuming it’s the power capacity is right around where you guys are very little transport cost there. So the realizations could be pretty good.

Michael Kennedy: Exactly. We are attracted to the local demand just because it’s low cost and able to supply the — it’s all incremental demand, too. So we’ll be able to grow into it. So that’s part of our low-cost growth strategy.

Joshua Silverstein: Okay. And then just on the HG acquisition as well. You highlighted the OpEx cost synergies. The biggest piece of the synergies you outlined previously was on the development optimization. I just wanted to see how that’s going, if that’s something that we’ll start to see more of a benefit of later on this year more in ’27 relative to what you’re seeing right now?

Michael Kennedy: Yes, definitely. That is the majority of the synergy. A perfect example is kind of on the completion — the completion stages per day. HG was in the 2, 3, 4 stages per day, we average over 14 stages per day. So just on this pad that we brought on the wells going south, they were doing 2 or 3 stages. This week, we’ve been doing 11 on that. So you can imagine the efficiencies and optimization and cycle times that come with that, and we did not underwrite that in our acquisition valuation. So that all accrues to our shareholders. So that’s the biggest one also with drilling to. We’re under 9 days per well. They were triple quadruple that. So putting that into the portfolio really brings forward all that value for us and is really going to drive the synergies going forward. .

Operator: Next question is coming from Neil Mehta from Goldman Sachs.

Neil Mehta: Yes. Slide 7 is really great, where you guys talk about the new propane dock capacity. And the base case is Slide 8 as well, I should say, most of them. The base case, I think, is pretty clear, but the export case is quite extreme by the summer. And so maybe you could talk about how real is this potential for that — for the max export case to play out? And what are the biggest gating factors for it not to play out?

David Cannelongo: Yes, Neil, this is Dave. I’ll take that one. I think you really got to hit it on the head, which is the max export case, while the world would love to see that happen to try and backfill just a portion of the LPG supply that’s lost globally. I mean you certainly are seeing reports about shortages, high canister prices in different parts of Central and Southeast Asia already and kind of the effects that’s having. So they would love for the U.S. to try and do the MAX export case. I guess what we were trying to illustrate was we really don’t have the inventory to do that. So let’s just say, if the war was to get resolved here even in the next few weeks, things will be reopened by the end of June. Let’s say, the world’s lost 120 million barrels or more of LPG, we can probably backfill about 30 of it here from the U.S. And so that’s really ultimately why we’re so constructive on IND propane pricing.

Even at that max export case, we don’t even come close to backfilling the demand supply loss and the demand that’s out there for global LPG, unfortunately.

Neil Mehta: And then — and so much of this is dependent on when the dock capacity is coming online. Can you just talk about, as you guys look at the future dock expansions and the stuff that slated for ’26, is everything tracking well?

David Cannelongo: Yes, I would say so. I mean, I think one of the large midstream players was talking about the commissioning of one of their projects kind of ongoing. I think that was a little bit ahead of where a few months ago, people would have pegged it kind of more middle of the summer. So I would say ahead here so far year-to-date in ’26. And typically, what you see with those projects as various companies that are building those do a great job of getting those projects online on time. LPG export capacity isn’t that complicated to build compared to some of the other like an LNG facility would be, for example, .

Operator: Next question is coming from Phillip Jungwirth from BMO.

Phillip Jungwirth: Sticking with the recent announcements in West Virginia, about a year ago, the state — they did sign the microgrids build. This was meant to track data centers. Just wondering how much of a help this has been in the conversations with hyperscalers? And then what are some of the other main positives that would favor West Virginia, which is right in your backyard versus other states within Appalachia?

Michael Kennedy: Yes, that has definitely been to help. So we really appreciate that [ microgrid bill ] and kind of put West Virginia front and center for all these discussions. West Virginia’s advantage is geographically, we put it in its 100 miles to the data center alley. It’s got the water. It’s obviously got the lowest cost natural gas and energy. It’s near the population centers on the East. It’s fairly cold. It’s got all the advantages. I think there was a report out there by an energy company at the same — all the attributes that you look for, they all converge in West Virginia. So we’re uniquely positioned there as well just because we produce over half of the state’s natural gas. So definitely a good position to be in.

Phillip Jungwirth: Okay. Great. And then a couple of quarters ago, you included a regional gas demand project list in the deck. I think you had Monarch on here as a 2030 startup, 430 million a day of demand. Now it looks like it could be bigger than earlier, at least the first phase. So without updating this slide, are there any others you could see maybe being pulled forward as far as timing or increase as far as magnitude. Of the 8 Bs a day, you’re showing on Slide 11. How much of this is either under construction or has reached FID now?

Brendan Krueger: Yes. I think if you look at the map on the — I don’t have the exact figures in terms of what’s under construction versus FID. But I think we would say of that 8 Bcf a day based on conversations we’re having and Justin talked about is, we see that well ahead of 10 Bcf a day. I think a lot of these projects and what has been publicly disclosed are the initial phases I think to the extent they can continue to build and scale those numbers will be quite larger. So we’re having a lot of those conversations. And some are speeding up. And so I think our view is you really see this start to take hold when you get out into that ’27, ’28, ’29 time period in terms of these facilities coming on. And it will be phased over time where you have like Monarch is a good example.

They’ve talked about their Phase 1, but that will continue to phase and grow. And that microgrid bill that I think was asked about before, it allows you to phase within a 4-mile halo. So some of these sites they have their 4-mile halo where they can continue to scale up over time within that 4-mile halo and still fall under the microgrid build in West Virginia.

Operator: Our next question today is coming from Leo Mariani from ROTH.

Leo Mariani: You’ve been really helpful in terms of providing kind of the production ramp post HG kind of given the guide in 2Q and then into kind of second half. I was hoping to see if maybe you could talk about just kind of something similar on capital. I mean presumably, maybe first quarter is kind of a low and CapEx picks up a little bit in the following quarters. I know, obviously, the growth capital could also be a component. And I would assume that all that growth capital would end up in the second half if you decide to spend it. So just any color there would be helpful.

Michael Kennedy: Yes. that’s correct. We have a full contribution for capital in the second quarter for HG. So that takes — for the second, third and fourth quarter kind of into the $300 million range, assuming we complete some of those pads we talked about earlier for the growth case. If we don’t do that, then it will step back down from the $300 million more to the kind of the $250 million range in the third and fourth quarter.

Leo Mariani: Okay. That’s helpful. And just on the synergies, obviously, you talked about the $80 million target. Would you expect that all to be realized here in 2026? Or can some of that linger into next year? And is the bulk of that just — it sounded like a lot of it was operating cost and G&A related, but is there a capital portion that will flow through there as well?

Michael Kennedy: Yes. No, that’s just for ’26 the $80 million. That accelerates actually on the go forward as we continue to improve and continue the synergies. And as we get the asset integrated into our operations, on a go-forward basis. So that’s just the ’26. I think we talked about synergies up to $1 billion over time. So we’re ahead of that right now. So that’s $80 million this year. I think it’s more like $100 million going forward on an annual basis after that.

Operator: Our next question today is coming from Doug Leggate from Wolfe Research.

Douglas George Blyth Leggate: I appreciate you having me on. I wonder if I could come back again to Slide 7 and 8. I just want to make sure I’m not missing something here. So your base case still looks still quite conservative. What would it take for you to change that? Because it seems, at least based on enterprise’s comments that exports are already running at record levels in April. So what would it take for you to reset that?

David Cannelongo: Yes, Doug, this is Dan again. it’s really just a question of how much inventory in the U.S. is or how little inventory in the U.S. is comfortable having as we enter the winter season. And when you see our base case dipping below the 5-year range, that usually sort of scenario happens, you see very, very strong demand here in the U.S. to try and keep those barrels onshore so that they are there for our winter season. So you get this type of war between domestic and international and that’s why we didn’t illustrate a stronger base case. But certainly, as I said earlier in my comments to Neil, the world would like us to do the MAX export case. If we could, we just as far as we don’t have enough supply for it.

Douglas George Blyth Leggate: Not to belabor the point, but I think Neil brought this up earlier. So just to be clear, is your view then on the premium to Mont Belvieu directly related to your view on exports. In other words, if price [indiscernible] exports go up, does your mont Belvieu premium get reset again in the second quarter in terms of your guidance…

David Cannelongo: We think parties that are selling spot cargoes in the second half of this year will be getting modest premiums in Mont Belvieu as we’ve seen in other times where there’s ample dock capacity, and there’s not enough inventory to go around for exports and domestic.

Michael Kennedy: But you’ll have higher Mont Belvieu pricing.

David Cannelongo: Exactly. .

Douglas George Blyth Leggate: All right. Well, this is a moving target. I get that. But my follow-up is going back to the data center comment. I just wanted to — Mike maybe it’s for you, I wanted to see if we can get some clarification. Everybody and their grandmother is trying to basically negotiate a data center supply deal. Obviously, you’ve got a bit of a geographical advantage if it’s in your backyard. But are any of your negotiations exclusive? Or are they all being put up to bid? Can you kind of walk us through what the nature of the negotiations looks like? And I’ll leave it there.

Brendan Krueger: Yes. I think for most of them, it’s a request for proposal to a number of parties. I think at the end of the day, we feel we’re well advantaged being an investment-grade producer. But to the extent we don’t get these and you still have this demand take place it should rise — cause a rise in local prices, which will obviously benefit from. So we’re certainly supportive of all of these projects to continue to get them off the ground. There’s only so much gas that can go around but we think it just drives ultimately an increase in local pricing, which will benefit from, I think, in a pretty significant way as well.

Douglas George Blyth Leggate: Where I’m going with this is get the deal or not you’re not going to give up market share, right? So presumably, you benefit regardless of who… .

Brendan Krueger: Yes.

Operator: Next question today is coming from Paul Diamond from Ciit.

Paul Diamond: Sticking on the AI and power contracts for a moment. Across the space, we’ve seen some variability in the term structure and where the — I guess, all these things settle. Can you talk about what you’ve seen in your conversations is like in your emerging like structure that’s most common? Or is it more highly variable based on end market needs?

Brendan Krueger: Yes. I think it depends on where the supply is coming from. So some of these deals that we’re looking at, we would look to supply off of our firm transport the pricing for that deal, if it’s coming off of our firm transport may be different than if Antero Midstream is building pipeline in state to supply a gas deal. So depending on the deal, the pricing could change. I think a lot of these guys, they’re seeing what we talked about, which is we talked about 5 Bcf a day of demand. We obviously cannot supply 5 Bcf a day of that supply. And so I think they’re getting a bit more nervous in terms of where is all the supply going to come from which we think will ultimately drive better pricing on these deals and rise — cause a rise in the local pricing. But it could take a local market index or could be tied to Henry Hub, and I think those are still up in the air at this point.

Paul Diamond: Got it. Makes perfect sense. And then sticking on, you guys talked a bit about the balance between gas and liquids on a medium-term basis. You talk a bit about how that structure might be? Is that more like normal cycle reactivity? Or is that a building of docks for more short-cycle response? Just how do you guys see that playing out?

Michael Kennedy: Yes, it’s a bit of both. What was really driving it is just a little bit more balance prior. We just put on our first dry gas pad and exceeding expectations. And just put it on like a month ago, first dry gas pad in over a decade. We have over 1,000 locations in the premium core of the Marcellus dry gas. So we need to develop that. and having it coincide with all its local demand, it will really drive kind of just 1 rig there for the foreseeable future. We’ll obviously have 1 rig in the liquids as well. Our Western portion of our acreage, and then we’ll have 1 that’s on the HG asset, and that kind of flows between dry gas and liquids. So it’s more kind of a blend. But just to really have a little bit more balance that will really drive our cost structure lower.

It will drive low-cost growth going forward and really optimize our margins and drive our EBITDA growth. So — we’re excited about it, but we really just need to tap into that acreage legacy acreage position we had and developed that.

Paul Diamond: Got it. And just 1 quick follow-up there. Do you see — I guess, do you see any value in building a large DUC inventory? Or is that — do you kind of like the structure you operate in the [indiscernible]

Michael Kennedy: Yes, I don’t know about a large one, but what we’re talking about is 3 pads right now, maybe enter into 2027 with 3 UPTs. That will be the call we make in the second half just based on local natural gas prices, but that’s about where we see our DUC inventory being on a go-forward basis.

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

Justin B. Fowler: I’d like to thank everybody for joining us on the First Quarter 2026 conference call. please feel free to reach out with any further questions. Have a good day.

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