ANTERO RESOURCES Corp Q3 FY2024 earnings call

• Drilling and Completion Efficiencies: 2024 operating performance set records. Drilling times reduced from 14 days in 2022 to below 11 days in 2024 (22% reduction). Completion stages per day averaged 12.1 in Q3 2024, with a monthly record of 13.3 in August 2024, a 51% increase from 2022. Cycle times declined to 126 days, 23% below 2022's 163 days. Well costs reduced by 8% since 2023 to the lowest since 2021.
• Reduced Capital Budget: 2024 drilling and completion capital budget reduced to $650M midpoint, a 28% decrease from 2023, while holding production flat. Sustaining maintenance production with 2 rigs and ~1 completion crew. In 2025, switching to e-fleet for completion activity, with potential well cost savings of $150,000 to $200,000 per well.
• Liquids and NGL Fundamentals: Export premiums for LPG sales were strong, with propane exports up 46% since 2021. Butane premiums were high. Antero has unconstrained access at the Marcus Hook terminal in Pennsylvania, allowing it to capture high export premiums.
• Natural Gas Market: Year-to-date natural gas power burn demand was a record, driven by AI data centers, crypto mining, and electric vehicles. Antero's firm transportation portfolio exposes it to growing LNG demand. Storage levels have shrunk by nearly 500 Bcf since March 2024, sitting at 167 Bcf above the 5-year average.
• Free Cash Flow and Capital Efficiency: Unhedged free cash flow breakeven at ~$2.20, benefiting from low maintenance capital requirements and high exposure to liquids. Antero has the lowest maintenance capital per Mcfe in its peer group at $0.52 per Mcfe, 41% below the peer average. Free cash flow uplift in 2024 from lower CapEx and higher C3+ NGL prices, with nearly $500M of incremental cash flow compared to 2023 while maintaining the asset base.

Liquids/NGLs: In the third quarter, Antero realized strong export premiums for LPG sales. C3+ NGL prices averaged higher, with propane exports averaging over 1.7 million barrels a day year-to-date, up 46% since 2021. Butane premiums were also strong. Antero has unconstrained access at the Marcus Hook terminal in Pennsylvania. Natural Gas: Year-to-date natural gas power burn demand was a record, averaging 1.4 Bcf higher than the previous year. Antero's firm transportation portfolio delivers 75% of its natural gas to the LNG corridor, and it has exposure to growing LNG demand and data center build-outs in West Virginia. Revenue contribution details weren't explicitly given in absolute terms with percentages, but the focus was on the performance of each segment's key metrics.

• 2024 drilling and completion capital budget reduced to $650M midpoint, a 28% decrease from 2023, with production held flat.
• In 2025, continue focusing on improving efficiency, with early results from e-fleet completion activity showing promise and potential well cost savings.
• Deferred completion of 2 DUC pads (one originally scheduled for Q3, another for Q1 2025) based on natural gas prices, with completion to be determined by natural gas price levels.
• Buyback strategy: First $600M of free cash flow to reduce debt (targeting credit facility down to 0 and paying down 2026 notes), then majority of free cash flow for buybacks.

• Potential impact of natural gas price fluctuations on the decision to complete deferred DUC pads, as these pads require higher natural gas prices for completion.
• Uncertainty around the timing and extent of Gulf Coast export capacity increases, which could affect LPG export premiums.
• Sensitivity of dry gas DUC completions to gas price levels, as these pads have lower Btu content and require specific price thresholds for completion.

Q: Bert Donnes with Truth Securities asked about guidance and buyback strategy.

A: Michael Kennedy said in 2024, 2 pads with 12 wells as DUCs were not completed, and buyback strategy is first $600M free cash flow to reduce debt, then buybacks.

Q: Arun Jayaram with JPMorgan asked about Northeast LPG export advantage and DUC completions.

A: Dave Cannelongo talked about Gulf Coast export capacity increases in mid-2025 and 2026, and Michael Kennedy said dry gas DUCs completion depends on gas price over 250 and 60-day front month pricing confidence.

Q: Leo Mariani with ROTH Capital asked about maintenance capital and production.

A: Michael Kennedy said maintenance capital around $700M for 3.3-3.4 Bcfe/day production, Q4 2024 guidance midpoint 3.35, and 2025 around same level.

Q: Ati Modak with Goldman Sachs asked about gas price realizations and DUC deferrals.

A: Michael Kennedy said same gas marketing strategy to flow gas to Gulf Coast and LNG corridor, and DUCs deferred are more liquids focused in certain areas.

Q: Josh Silverstein with UBS asked about e-fleet and hedging strategy.

A: Michael Kennedy said e-fleet is a 2 pad trial, and they're watching the gas price curve for hedging decisions.

Q: Kevin MacCurdy with Pickering Energy Partners asked about CapEx reduction breakdown and 2025 budget.

A: Michael Kennedy said $15M from efficiencies and $10M from deferred turn in lines, and 2025 budget includes efficiencies and lower lateral lengths but rolled in efficiencies.

Q: David Deckelbaum with Cowen asked about drilling carry delta and maintenance levels.

A: Michael Kennedy said drilling carry delta is around $30M, and maintenance level is about lowest capital to maintain 3.3-3.4 Bcfe/day production by capturing efficiencies.