Oct 29, 2026 earnings call — NGL strength and margin enhancement progress
Production rose 23% year-over-year to a company record of 4.2 Bcfe per day.
Revenue $1.6B (est $1.6B) · EPS $1.19 (est $0.97)
Key quotes
"As mentioned in my remarks a moment ago, Antero's current spot C3+ NGL prices are at the highest levels realized since 2022."
"Based on transactions we have executed on to date, we expect to achieve $140 million of our $300 million target by mid-2027."
"As depicted on slide 3, per a recent public analysis by Enverus, we have more than 1,400 core drilling locations remaining."
Analyst Q&A 14
Q4 volumes and NGL tailwind
Q (Neil Mehta · Goldman Sachs): How much of Q4 curtailment was due to third-party outages versus economic reasons, and how big is the NGL pricing tailwind into Q4 and 2027?
A: Management guided to 4.3 Bcf with 15 Bcf to 20 Bcf of curtailments and said many curtailments came from downstream outages and weak shoulder-month pricing. They can shut in local dry gas at $1.25 or below while still producing liquids when liquids are over $60 a barrel, and noted local dry gas is hedged at basis around $0.90. They also said Q4 NGL pricing will materially boost free cash flow versus Q3 and highlighted the scale of C3+ production.
"The guidance is at 4.3 Bcf with 15 Bcf to 20 Bcf curtailments." — Mike Kennedy (CEO)
Price differentials and Clarington deal terms
Q (Gabe Daoud · Truist): How will differentials to NYMEX and to international/domestic NGLs change into 2027, and how should we think about the Clarington supply agreement pricing?
A: Management said Q3 is the weakest season for differentials, with Q3 around $0.30 back to index, Q4 improving to about $0.20, and 2027 maybe flat to $0.10 back as they optimize firm transport. They said they can capture premium cash cost benefits through transport optimization. On Clarington, they said they currently have about 400 million a day going there and longer-term deals can be in the $0.20 to $0.25 above M2 range, with shorter month/day sales closer to M2 plus $0.10-$0.15.
"That Clarington market is in the $0.20 to $0.25 above M2, if you can do longer term deals." — Brendan Krueger (CFO)
Remaining FT optimization details and cash costs
Q (Arun Jayaram · JPMorgan): Can you elaborate on the next $160 million of FT optimizations and the timing, and how will cash production expense trend into 2027?
A: They said of the remaining $160 million, about $100 million comes from the expiration of liquids transport contracts and about $60 million from dry gas development as firm transport rolls off. For Q4 cash production expense is a touch higher due to fuel on higher commodity prices but the base business is around $2.05 and they expect cash production expense to trend down in 2027 as optimizations and local gas sales take effect.
"I believe it's $100 million of the $160 million remaining." — Mike Kennedy (CEO)
East Side Express and pad completion
Q (Kevin MacCurdy · Pickering Energy Partners): Where does East Side Express get gas from and will it use new production or shift existing volumes? Also, is the new pad liquids-rich and tied to high propane prices?
A: They said East Side Express runs east-west across their dry gas acreage to connect 100,000 undeveloped acres with multiple pipeline interconnects, giving flexibility to flow to the best price and supporting dry gas development while also helping rebalance their production mix. On the pad, the Barner Pad is a 1,300 BTU DUC being completed now on the western field because C3+ prices are over $60, so they are completing it now rather than waiting.
"It connects that 100,000 acres and allows for that dry gas development to find the best price." — Mike Kennedy (CEO)
2027 capital plan and firm sales duration
Q (David Deckelbaum · Stifel): How much growth capital next year and will the capital plan mirror this year? Also, how long are the firm's sales agreements likely to be?
A: They said the capital plan will be similar to this year: a consistent program of three rigs and two completion crews, with discretionary decisions based on commodity prices and hedges in place (they hedged over 100 million a day at $3.50 for 2027 and 2028). For firm sales, they said Clarington transactions are often one to two years now but can extend over time, and replacing a 200 million a day contract with M2 plus sales could add about $75 million to $80 million of margin; they target 300 million by year-end 2028 and plan to double beyond that.
"If you replace this 200 million a day contract with volume at an M2 plus contract off of that pipe, it is upwards of $75 million to $80 million of margin enhancement." — Brendan Krueger (CFO)
400 mm/d in 1 Bcf target and growth baseline
Q (Jacob Roberts · TPH): Is the 400 million a day optimization included in the 1 Bcf target and is the $50 million uplift net of the realization haircut? Also, should 2027 growth start from 4.3 or an uncurtailed 4.5?
A: They confirmed the 400 is included in the 1 Bcf total and that the $50 million figure is net of the realization impact. For growth, they said the right starting point is year-over-year, noting 'the average of 26 high single-digit growth over the average of 26,' meaning growth should be considered year-over-year.
"The 400 is inclusive in that 1 Bcf, so it's a total of 1 Bcf, the $50 million is net of the realization impact." — Mike Kennedy (CEO)
Which FT to optimize and Clarington demand size
Q (Betty Jiang · Barclays): Which markets would you trade away exposure from to lower transport cost, and how much of the 16 Bcf/day power demand comes from Clarington and how big can that market grow?
A: They said they are optimizing, not trading away volumes, and will target where demand pull pays premiums; the 1 Bcf target is their goal and they'll pursue the best margin response across the FT portfolio. On Clarington, they said they have about 400 a day flowing today and estimate of the 16 Bcf a day power demand, roughly 5-6 Bcf a day is being pulled from that market, so increasing the 400 by another 1 Bcf a day is not unrealistic given demand pull.
"I think given the demand pull we're seeing at that market, of that 16 Bcf a day, you have at least, I'd call it 5-6 Bcf a day being pulled out of that market." — Brendan Krueger (CFO)
ATEX ethane use, freight, and structure
Q (Phillip Jungwirth · BMO): Could ATEX be converted from ethane service to other C3+ transport, how do elevated freight rates affect C3+ netbacks, and is the AR/AM structure still optimal amid M&A?
A: They said they still expect the pipeline to remain ethane service, though other products are possible but not their focus, and overall they will continue margin-enhancement optimizations. On freight, they expect rates to stay elevated at least through the first half of 2027 with some relief later in the year as supply dynamics evolve. On structure, they said AR/AM is advantaged: AM's lower cost of capital helps regional growth projects and controlling midstream is strategically important for Appalachia development.
"I think for 2027, market expectation is things will stay pretty elevated at least through the first half of the year." — Dave Cannelongo
C3+ drivers and completion mix
Q (Subash Chandra · StoneX): How much of the October C3+ move is war related and would your view change if peace returned? Also, will next year's completion schedule favor more NGL-focused pads?
A: They said current elevated propane and butane prices align with roughly $100 oil and that the war has reduced waterborne LPG by about 25% due to Strait of Hormuz impacts, which supports NGL strength if that persists. On completions, they said their development plan aims for balance: roughly 50/50 between dry gas and liquids on development pads going forward and that production mix remains similar, so they do not plan a big shift to NGL emphasis.
"We're still down about 25% of waterborne LPG due to the impacts in the Strait of Hormuz, just not as much of a recovery on the LPG side in that region." — Dave Cannelongo
2027 volumes, inflation, and gas realizations
Q (Leo Mariani · ROTH): Does the 2027 Bcfe/day guide imply limited organic growth by choice, are you seeing inflation, and why didn't earlier hoped-for gas premiums materialize?
A: They said the 2027 outlook is a low 4.5 number reflecting curtailment risk and that without those curtailments you would be above 4.5. On inflation, they are not seeing material service cost pressure—maybe 1% on some raw materials—but nothing notable. Regarding gas realizations, they said September and October produced historic weak regional gas prices (with some weekend lows near $0.60) driven by downstream outages, which they did not sell into and instead used flexibility to delay sales into stronger months.
"I think September and October, we saw the lowest regional gas price we've ever seen." — Mike Kennedy (CEO)
Timing of FT optimization gains and beyond 2028
Q (Paul Diamond · Citi): Will the additional $55 million in 2027-28 be achieved in chunks or gradually, and is doubling beyond 2028 driven by contract roll or other actions?
A: They said the additional $55 million will be achieved ratably over 2027 and 2028 as they sign incremental sales agreements. For the doubling beyond 2028, they expect to replace high-cost FT that goes away with longer-term basin sales agreements that materially improve all-in netbacks and are confident in that ability given current interest.
"So ratable throughout the next couple of years is a good way to think about it." — Brendan Krueger (CFO)
M&A stance and buyback approach
Q (John Abbott · Wolfe): How does shrinking premium for core acreage change your M&A view, and how will you approach buybacks if NGLs spike?
A: They said they are buyers of acreage and believe they have an advantage as one of the few investment-grade companies with scale, plus upstream and midstream control that makes them a logical consolidator in West Virginia. On buybacks they are opportunistic, often using 10b5-1 plans and multi-factor rules tied to commodity levels, free cash flow, debt, and M&A opportunities; they noted they repurchased 15.5 million shares over the last five quarters and hope to continue opportunistically.
"Being one of the few investment-grade companies with scale already, we have an advantage." — Mike Kennedy (CEO)
HG efficiency gains and FT choices
Q (John Annis · Texas Capital): What operational changes drove D&C improvements at HG assets, and can the FT portfolio be both lower cost and flexible to capture premiums?
A: They said they applied their operating model and experience to HG, increasing completion speed (13-14 stages per day versus 3-4) and cutting drilling days (sub five days per 10,000 feet versus double digits), which drove efficiencies and synergies now over $100 million for the year. For FT, they said they have 28 paths and can identify which are margin-enhancing to keep, while replacing others with local firm sales, allowing the portfolio to be both lower cost and flexible.
"We have over 1,500 wells of experience, and we brought our operations team, which is the best in the business to do it." — Mike Kennedy (CEO)
Revenue capture and long lateral plans
Q (Josh Silverstein · UBS): How are you capturing revenue vs. cutting costs, and can you keep pushing average lateral lengths and the related economics?
A: They said they capture revenue by using their transport to flow physical volumes to the best paths and to the coast, capturing the arb between international and U.S. pricing rather than just trying to do it without capacity. On laterals, they expect next year drilling to average 18,000 feet (a record), highlighted a completed 25,000-foot lateral with cost-per-foot advantages, and said they aim to push beyond 30,000 feet in coming years to improve economics and planning efficiency across many locations.
"I think next year our drilling is going to average 18,000 feet, which is a record." — Mike Kennedy (CEO)