Granite Ridge Resources' Q3 2025: Contradictions Emerge on Inventory Strategy, 2026 Capital Allocation, CapEx Rig Plans, and Permian vs. Gas Investment Focus

Date of Call: November 7, 2025

Financials Results

• Revenue: $112.7 million, up from $94.1 million in the prior-year period
• EPS: $0.11 per diluted share (net income); adjusted EPS $0.09 per diluted share

Guidance:

• Maintaining full-year 2025 production guidance of 31,000–33,000 BOE/d; oil ~50% of mix.
• Full-year 2025 CapEx expected $400–$420 million; Q4 '25 CapEx implied ~ $125M (timing of acquisitions).
• Q4 '25 production expected to grow high single digits versus Q3.
• 2026 framework: above $60/bbl pursue measured growth with modest outspend; sustained <$55/bbl pivot to maintenance with ~ $225M CapEx.
• Hedging: target ~75% of quarterly production; ~50% of expected 2026 volumes already hedged.

Business Commentary:

• Production and Financial Growth:
• Granite Ridge Resources reported an average daily production increase of 27% year-over-year to 31,900 barrels of oil equivalent per day in Q3 2025.
• 
• Adjusted EBITDAX rose 4% from the prior year period to $78.6 million.

• This growth was driven by disciplined capital allocation, operational excellence, and strong execution across the company's platform and operating partners.

• Operated Partnership Success:

• Admiral Permian Resources, the company's largest and longest-standing operator partnership, now controls 30 distinct drilling units across the Permian Basin.
• Admiral's production contributed 7,400 BOE per day net to Granite, representing 23% of Granite Ridge's total production.

• The partnership's success was attributed to efficient drilling unit level acquisitions and cost control technologies.

• Financial Strength and Capital Structure:

• Granite Ridge ended the quarter with a leverage ratio of 0.9x, significantly below its long-term target range of less than 1.25x.
• The company successfully issued $350 million of senior unsecured notes due 2029 with an 8.875% annual coupon, increasing pro forma liquidity to $422 million.

• These actions enhance financial flexibility and maintain a strong balance sheet.

• Appalachian Basin Acquisition and Performance:

• Granite Ridge added over 1,500 net acres in the Appalachian Basin this year, consistently outperforming underwriting expectations.
• The company invested $43 million in the third quarter, adding 27 net wells in Permian and Appalachia.

• The increase in acquisition activity was driven by attractive opportunities in the region, supported by strong underwriting performance.

• Capital Expenditure and Inventory Strategy:

• Granite Ridge plans to spend $120 million in 50 transactions to add 75 net locations to its inventory by the end of 2025.
• The company aims for a three- to five-year inventory duration, emphasizing control over operator partnerships.
• This strategy is designed to balance risk and opportunity, with a focus on having a manageable inventory duration to maintain balance sheet health.

Sentiment Analysis:

Overall Tone: Positive

• Management called Q3 a "strong quarter" with "continued operational outperformance," highlighted leverage of 0.9x "well below" target and pro forma liquidity of $422M; emphasized disciplined capital allocation, partnership scalability and confidence Granite Ridge is "well positioned" for disciplined growth in 2026.

Q&A:

• Question from Michael Scialla (Stephens Inc.): I want to see if you could talk a little bit more about your third and fourth partnerships. You said they're both moving strategic plans forward. Anything else you can tell us there in terms of what those plans might look like and where they are in terms of potentially drilling or adding acreage?
  Response: Both new Permian partnerships are in acreage aggregation mode; management expects ~6 months to assemble ~18 months of inventory before committing full-time rigs, with initial transactions closing in Q4 and limited development in 2026 until inventory is aggregated.

• Question from Michael Scialla (Stephens Inc.): You mentioned you would in a $55 or lower oil price environment cut CapEx back to $225 million next year. Can you provide a little bit more detail on that? I assume most of the production would come out of the partnerships. Maybe how much flexibility you have there in lay down rigs and crews? And how would the mix change going forward in that scenario versus your traditional non-op position versus the partnerships?
  Response: If prices fall to ~$55/bbl, management would cut drilling and reduce CapEx to ~ $225M by leveraging control of operated partnerships to push activity out and reallocate spend toward opportunistic acquisitions and PDP-style transactions.

• Question from Michael Scialla (Stephens Inc.): So not really a change in the mix between the traditional non-op and the partnerships but just both would be lower and less focus on drilling, more focus on acquisitions?
  Response: Yes — mix remains similar but overall activity lowers; focus shifts from drilling toward opportunistic acquisitions.

• Question from John Annis (Texas Capital Securities): How should we think about the growth trajectory in the fourth quarter and into 2026 with Admiral running at full steam and Petrolegacy ramping? And then is it fair to assume PLE's production shows up more towards the second quarter or midyear?
  Response: Q4 '25 production expected to be up high-single-digits versus Q3; Admiral will run two rigs through 2026; PLE production anticipated to begin showing up in late Q2/midyear.

• Question from John Annis (Texas Capital Securities): What do you see as the ideal length of inventory you'd like to get to? And how do you weigh that with the commodity underwriting risk that comes with that longer-dated inventory?
  Response: Target inventory of three to five years; prefer controllable, partnership-operated inventory rather than long-term acreage to limit commodity underwriting risk.

• Question from Noah Hungness (BofA Securities): LOE was a little higher than we thought for the third quarter. Can you maybe just talk about how we should expect that to trend in 4Q and also for '26?
  Response: LOE rose due to higher Permian saltwater disposal and service costs; expect to be towards the higher end of 2025 guidance; 2026 LOE outlook not yet provided and will be guided later.

• Question from Noah Hungness (BofA Securities): Do you have Waha hedges on today for second half '26 and beyond? And would you consider adding them or adding more to eliminate your Waha exposure given how strong the forward curve?
  Response: No current Waha basis hedges; management is evaluating adding basis hedges and alternative solutions (e.g., gas-to-power offtake) to mitigate Waha exposure.

• Question from Noah Hungness (BofA Securities): How should we think about the pricing for that? Is it power exposure? Is it a premium to Waha? Is it flat price?
  Response: Power offtake would provide power exposure realized as a premium to Waha.

• Question from Phillips Johnston (Capital One Securities): How should CapEx trend into Q4? The implied Q4 range is wide; should we steer towards the midpoint, low end or high end?
  Response: Q4 CapEx is largely timing of acquisitions; management expects Q4 around $125M with a large portion tied to closing remaining acquisitions.

• Question from Phillips Johnston (Capital One Securities): If current strip prices hold, how should we think about capital allocation for next year in terms of oil versus gas? Would you keep investment mix roughly the same or lean into gas more?
  Response: Allocation is returns-driven: expect significant oil weighting in the Permian where returns are best, while continuing non-op growth in Appalachia (rich condensate) where attractive opportunities exist.

Contradiction Point 1

Ideal Length of Inventory

It involves the company's strategy regarding inventory levels, which can impact future production growth and financial performance.

What is the ideal inventory duration, and how does it balance with commodity underwriting risks associated with longer-dated inventory? - John Annis (Texas Capital Securities, Research Division)

2025Q3: We actually love where we're at right now. Three to 5 years of inventory feels like the right amount of inventory for us. - Tyler Farquharson(CEO)

How do you balance inventory growth, expansion, and leverage management? - Unidentified Analyst (Texas Capital)

2025Q2: We'll look at the acquisition environment, look at our balance sheet, look at our leverage situation and then we'll make a call on the timing of adding to our inventory. - Tyler Farquharson(CEO)

Contradiction Point 2

Capital Allocation for 2026

It involves the company's plans for capital allocation in the following year, which can impact future investment strategies and financial performance.

Assuming current strip prices hold, how should capital allocation between oil and gas be approached next year—should the investment mix remain similar, or be adjusted to increase gas allocation slightly? - Phillips Johnston (Capital One Securities, Inc., Research Division)

2025Q3: It's all returns driven, right? Where we're seeing the best opportunity now continues to be in the Permian. So I'd expect a very significant oil weighting. That being said, outside of the Permian, we are via the traditional non-op strategy, having a lot of success in Appalachia, and that's more rich condensate phase. - Tyler Farquharson(CEO)

What drives the higher oil mix in the second half of the year? - John Phillips Little Johnston (Capital One Securities, Inc., Research Division)

2025Q2: We could add a fourth rig by 2026, running three now. Two new partners are aggregating inventory. With strong A&D activity, we expect CapEx to be similar to this year or higher. - Tyler Farquharson(CEO)

Contradiction Point 3

CapEx and Rig Strategy

It involves the company's capital expenditure and rig strategy, which can impact future production capacity and financial performance.

Can you provide more detail on cutting CapEx to $225 million next year if oil prices fall below $55? How much flexibility do you have in reducing rigs and crews from partnerships? How would the production mix shift between traditional non-op positions and partnerships in that scenario? - Michael Scialla (Stephens Inc., Research Division)

2025Q3: We'd expect to see coming out of the non-op portfolio, operators act rationally. So we'd expect to see a lot less inbound AFEs on the non-op piece. Then on the operated side, on the operated partnership side, we have full control over the timing and the development pace of those partnerships. - Tyler Farquharson(CEO)

Can you provide more details on the 2026 investment program, particularly regarding rigs? - Michael Stephen Scialla (Stephens Inc., Research Division)

2025Q2: We could add a fourth rig by 2026, running three now. Two new partners are aggregating inventory. With strong A&D activity, we expect CapEx to be similar to this year or higher. - Tyler Farquharson(CEO)

Contradiction Point 4

Permian Investment Focus and Gas vs. Oil Allocation

It involves changes in the company's investment priorities in the Permian, affecting the balance between oil and gas investments, which can impact financial forecasts and growth strategies.

Assuming current strip prices remain stable, how should capital allocation for next year be structured between oil and gas? Would you maintain the current investment mix? Or would you increase the gas allocation compared to previous levels? - Phillips Johnston (Capital One Securities, Inc., Research Division)

2025Q3: It's all returns driven, right? Where we're seeing the best opportunity now continues to be in the Permian. So I'd expect a very significant oil weighting. That being said, outside of the Permian, we are via the traditional non-op strategy, having a lot of success in Appalachia, and that's more rich condensate phase. We're -- we've been very successful this year on picking up a lot of inventory and acreage in that part of the play in Ohio. And we're starting to see AFEs come in. - Tyler Farquharson(CEO)

How are you assessing the opportunity from controlled capital and traditional non-op structures given the current supportive natural gas environment? - Derrick Whitfield (Texas Capital)

2024Q4: The greatest gains are in Permian non-op deals and the condensate window of the Utica. - Luke Brandenberg(CEO)