Growth Catalysts

• Fracture stimulation of 4 new wells expected to come on production in early December (timing on schedule).
• Production growth driven by 2025-drilled wells: Q3 2025 avg production 4,254 BOE/d (+40% YoY; +~40% vs 3,032 BOE/d prior-year quarter).

Business Development

Financial Highlights

• Revenue: $15.0m in Q3 2025 (+15% YoY) despite oil prices down 18%.
• Adjusted EBITDA: $11.1m (+9% YoY) vs $10.1m; offset by higher operating expenses from higher production.
• Net income and EPS: Q3 2025 net income $3.6m; basic EPS $0.10 vs $0.14 prior-year quarter; explained by -$1.8m swing in noncash unrealized mark-to-market hedges.
• Netbacks: decreased 23% to $30.84/BOE vs $40.01/BOE due primarily to lower prices.
• Operating expense per BOE: $7.37/BOE vs $6.63/BOE (+11%); due to reassessed production tax adjustments adding $0.80/BOE. Excluding adjustments, OpEx would have been $6.57/BOE (-1% YoY).
• Credit facility reaffirmed: $65m borrowing base (led by Bank of Oklahoma). Redetermined again in October at the same $65m.
• Balance sheet: net debt end of September $42.8m; available borrowing capacity $18.5m.
• Tax adjustment: one-time true-up of production taxes from purchaser reassessments; management described it as onetime only.

Capital Funding

• Stock buyback: repurchased ~568,000 shares total since the September 2024 start of the program (management referenced ~570,000 shares).
• Capital allocation: continuing buybacks as working capital allows.
• Leverage/repayment: guidance-related expectation to pay down $8m–$10m in Q1 2026 due to timing of spending to bring wells online.
• No specific cash runway or additional debt amount beyond net debt and credit facility details.

Strategy & Ops

• 2025 execution focus: actively fracture stimulating 4 wells for early December production.
• 2026 drilling posture: likely recommending to the Board to keep production flat to slightly growing near year-end levels; dependent on oil prices in December/early January.
• Hedging approach shift (October hedges): with a “bad” forward curve, management chose puts rather than collars/costless structures to protect downside while avoiding upside cap; intent that oil will eventually turn and that producers shouldn’t be capped.

Market Outlook

• Early December production: 4 new wells expected to come on production in early December; exit 2025 at an all-time high production rate.
• Leverage: management comfort around ~1x net leverage at year-end (question confirmed still comfortable).
• Hedging: October hedges referenced as primarily ~$50 puts (commented by analyst; company did not fully dispute framing).
• 2026 drilling program: depends on where prices are in December/early January; with current lower prices, less capital in ground but maintain flat/slight growth.

Risks & Headwinds

• Lower oil prices: Q3 oil prices down 18% YoY contributing to netback -23% to $30.84/BOE.
• Noncash hedge volatility: -$1.8m negative swing in noncash unrealized mark-to-market on hedges impacting EPS comparison.
• Operating cost distortion from one-time tax true-up: purchaser reassessed production taxes adding $0.80/BOE to Q3 2025 OpEx; management expects onetime only.
• Macro/forward curve uncertainty: described forward curve as “so bad” that costless collars/certain structures were less workable; impacts hedging strategy and confidence in near-term price path.
• Potential operational risk at Forguson well: production described as fairly flat; management will monitor how stimulation fluid “comes back,” and indicated they likely won’t drill another well there without higher prices (oil must be higher to justify other activities).