Granite Ridge Resources, Inc Q3 FY2025 earnings call

• The quarter highlighted the strength of the business model with disciplined capital allocation, operational excellence, and strong execution.
• Average daily production increased 27% YOY to 31,900 BOE/day. Adjusted EBITDAX was $78.6 million, up 4% YOY.
• Capital expenditures totaled $80.5 million, with $64 million in development and $16.5 million in acquisitions. Leverage ratio was 0.9x, below the long-term target.
• Enhanced capital structure and liquidity with a reaffirmed $375 million borrowing base and successful issuance of $350 million of senior unsecured notes.
• 2025 is an inflection point for scaling the operator partnership platform, with ~50% of capital spending deployed from partnerships. Admiral Permian is successful, with 63 producing wells and 14 in progress.
• Traditional non-op business delivered stable cash flow, with outperformance in the Appalachian Basin.
• Expect to invest an additional $47 million before year-end to secure 38 net locations and acreage in the Utica play.

In the third quarter, average daily production increased 27% year-over-year to 31,900 barrels of oil equivalent per day. Adjusted EBITDAX rose 4% from the prior year period to $78.6 million. Revenue for the third quarter was $112.7 million compared to $94.1 million in the prior year period. Admiral Permian Resources, the largest and longest-standing operator partnership, now produces 7,400 BOE per day net to Granite, representing 23% of Granite Ridge's total production.

• Full year 2025 capital expenditures expected to be $400 million to $420 million, with $120 million invested in 50 transactions adding 75 net locations.
• 2026 guidance: above $60 oil, pursue measured growth with modest outspend; below $55 oil, pivot to maintenance mode with ~$225 million CapEx.
• Production guidance for 2025 remains 31,000 to 33,000 BOE per day, with oil representing roughly 50% of the mix.

• Commodity market volatility.
• Uncertainty in global supply growth affecting oil prices.
• LOE higher than expected due to increased saltwater disposal, contract labor, and other service costs in the Permian Basin.
• Weak natural gas prices in Waha and uncertainty around future transport infrastructure.

Q: Talk a little bit more about your third and fourth partnerships.

A: Both partnerships are Permian focused, in aggregation mode. One focuses on emerging Permian plays, the other on the Midland Basin. They need 6 months to aggregate 18 months' worth of development inventory before full-time rig operation. Some transactions closing in Q4.

Q: In a $55 or lower oil price environment, cut CapEx back to $225 million next year. Provide more detail.

A: Non-op portfolio will see less AFEs; operated partnerships have control over timing and development pace. Can reallocate dollars to inventory acquisitions and PDP-style transactions.

Q: Understand lumpiness quarter-to-quarter, how to think about growth trajectory in Q4 and 2026.

A: PLE production contribution midyear. Admiral running 2 rigs, expect high single-digit production growth in Q4 2025.

Q: Talk about LOE trend in 4Q and 2026.

A: LOE higher in 2025 due to Permian saltwater disposal costs; will be towards higher end of guidance. No 2026 guidance yet, will evaluate with production expectations and operated partners.

Q: Waha natural gas hedges and exposure.

A: No current Waha basis hedges, considering adding them. Also looking at gas to power projects for Waha gas.

Q: How should we think about CapEx trend into Q4.

A: Development capital came in as expected, timing of acquisitions shifted to Q4. Still expect full year guidance, Q4 CapEx around $125 million.

Q: Capital allocation for 2026 in current strip prices.

A: Significant oil weighting in Permian; successful in Appalachia with rich condensate phase, expect additional capital spending there.