Antero Resources Q4 2024 Earnings Call Summary

Management Comments

1) Historical and Forecasted Natural Gas Production

• 2024 production: Averaged 3.4 Bcf/d, 2% above initial guidance.

• 2025 production forecast: Expected to increase by 50 MMcf/d YoY, but within current firm transport limits.

• Natural gas liquids (NGL) production: Expected to remain strong (~38% of total production).

  • Ethane contract expiring in Q1 2025, freeing up 10,000 Bbl/d of ethane for gas sales at NYMEX Henry Hub + $0.20/MMBtu, rather than discounted ethane pricing.

  • This results in a 30 MMcf/d lower reported production equivalent, but higher economic value.

  • Quote: “That will now be in the gas stream, getting NYMEX, Henry Hub plus $0.20, so economically much better.”

2) Production Curtailments & Shut-ins

• Deferred two lean gas pads in 2024 but brought them back online after securing hedges above $3/mcf.

  Quote: “After deferring two lean gas pads in 2024, we added natural gas hedges that tied to the volumes associated with those two 1200 BTU gas pads. Locking in prices above $3 per mcf assured us that we would capture attractive rates of return from these well

3) TIL & DUCs (Turned-In-Line & Drilled but Uncompleted Wells)

• Q1 2025 Activity:

  • 16 wells brought online in January 2025, with most capital spent in 2024.

    Quote: “All those 16 wells, the vast majority of that capital was in '24. Those were put on in January, turned to sales.”

• DUCs Remaining for 2025:

  • One DUC pad with 7 wells set to be completed and turned online in Q3 2025. This is part of a structured approach to maintaining production efficiency.

    Quote: “We brought on 16 wells in January throughout the month, and then we still have one DUC pad, like you mentioned, with seven wells, that'll be Q3.”

• Total Planned Well Completions for 2025:

  • 62.5 net wells expected to be completed, up from 41 in 2024.

  • Slightly shorter laterals (~13,800 ft in 2025 vs. 15,700 ft in 2024), but increased efficiency in cycle times expected to offset impact.

  • Efficiencies driving improvements:

    • Drilling times: Reduced to 10 days per well.

    • Completion rates: 12.2 stages/day in 2024, peaked at 13.2 stages/day in Q4 2024.

    • Overall cycle times: Down to 123 days in 2024 (-25% vs. 2022).

4) Hedging, Realized Prices, and Breakeven Costs

• 2024 breakeven: $2.20/MMBtu, generating $73M in FCF even at low prices.

• 2025 hedge strategy: Added wide collars for 2026 to cover lean gas volumes.

• Realized natural gas price premium: Expected to rise to $0.10–$0.20 above NYMEX in 2025 (vs. $0.02 in 2024).

• Premium from new LNG projects: By 2026, TGP 500L premium expected to increase from $0.14 (March 2025) to $0.50/MMBtu.

5) Rig & Frac Crew Activity

• 2024 rig count: 2 rigs, 1.1 frac crews on average.

• 2025: Same rig count (2 rigs), 1 full-time frac crew, with a spot crew for efficiency.

6) New Pipelines, LNG, & Infrastructure Projects

• Plaquemines LNG (Venture Global): First export cargo on Dec 26, 2024, ramping faster than expected. Now exporting 1.5 Bcf/d.

• Corpus Christi Phase 3 & Golden Pass LNG to increase LNG corridor demand in 2026.

• Antero’s takeaway advantage: Holds 570,000 MMBtu/day firm delivery to TGP 500L, 63% of supply for Evangeline Pass pipeline.

7) Market Activity & Outlook

• Natural gas storage: 111 Bcf below 5-year average, 200 Bcf below last year.

• EIA storage withdrawals: 7.9M barrels (second-largest ever on Jan 24, 2025).

• LNG exports at record highs: 1.8 MMbbl/d propane exports in early 2025, +9% YoY.

• Market tightening expected in H2 2025:

  • “We believe today’s low rig count combined with an upward step in demand will support a continued tightening of inventories.”

Q&A Section

1) Gas Macro & Supply Response

• Antero cannot increase supply much beyond maintenance levels due to firm transport limits.

• Quote: “All of our firm transport is filled, and we’re not selling any local gas.”

2) Drilling Joint Venture (JV)

• Antero signed a new JV agreement (15% working interest, pays more than 15% of costs).

• Benefit: Enables a two-rig, consistent program while keeping capital spending lower.

3) Production Guidance & Takeaway Capacity

• Increase of 50 MMcf/d YoY does not require additional transport capacity.

• Quote: “That’s still within our existing firm transport capacity, not selling any local gas.”

4) Hedging & Pricing Strategy

• No fixed target for hedging, but will lock in hedges when gas prices exceed $3/MMBtu.

• Future gas price exposure: Prefers to stay unhedged to capture upside from LNG-driven demand.

• TGP 500L market impact:

  • “We think actual differentials will be higher than market strip due to competition for gas.”

5) CapEx & Cost Outlook

• 2025 CapEx: $650M–$700M, includes pre-purchased materials.

• Tariffs on imported materials: Potential $5M–$10M impact, already factored into guidance.

6) Return of Capital & Share Buybacks

• Debt reduction plan:

  • $500M debt repayment in 2025 (credit facility + 2026 notes).

  • Then, 50% of free cash flow to share buybacks.

• Long-term capital structure: Targeting zero net debt.

7) Market Risks (TTF, LNG, and Demand Shifts)

• Europe’s TTF spreads remain strong, supporting US LNG exports.

• Quote: “We track LNG export economics closely, and spreads remain very supportive.”

8) Service Costs & Efficiency Gains

• 2024 well costs: $9.25/ft

• 2025 expected well costs: Low $900s per foot due to lower drilling contract rates.

9) Ethane & NGL Pricing

• 2025 ethane differential expected to improve due to expiring low-margin contracts.

• Propane & NGL strategy:

  • Locked in most domestic propane at a premium to Mont Belvieu.

  • Higher export demand expected to support pricing.

  • “We’ve locked in a sizable portion of our export volumes already.”

Key Takeaways for Commodity Analysts

1. Natural gas production: Holding steady at 3.4 Bcf/d, minor growth (+50 MMcf/d).

2. Tight market expected in H2 2025, benefiting Antero’s premium pricing.

3. New LNG export growth (Plaquemines, Corpus Christi, Golden Pass) to support pricing.

4. Hedges only for high-return lean gas pads ($3/MMBtu+), otherwise minimal hedging.

5. FCF breakeven remains industry-leading at ~$2.20/MMBtu, with $1.6B FCF expected in 2025.

6. CapEx stable at $650M–$700M, service costs declining slightly.

7. Debt repayment first ($500M in 2025), then share buybacks.