HPK

• Overall Operational Execution:
  • Production in Q2 2026 was flat sequentially relative to Q1 2026, and came in above the high end of the company's full-year guidance range.
  • 17 of the planned 26 full-year operated wells were drilled, and 24 of 33 planned wells were completed in the first half of 2026, following a decision to pull forward completion activity to lock in attractive fracking pricing and continue working with a high-efficiency SimulTrack crew. 20 wells have been turned online year-to-date, putting the company on track to hit its four-year target of 37 turn-in-lines.
  • First half 2026 capital spending reached the mid-to-upper 60% range of the full-year annual budget, up from the originally planned 60%, with no increase to the total full-year budget.
• Cost Performance:
  • First half unit LOE came in approximately 13% below the midpoint of the company's four-year guidance, at $7.56 per BOE. These cost savings are durable, driven by long-term infrastructure improvements, electrification, and ongoing field optimization.
  • Drill, complete, and equip costs remained in line with management expectations.
• Workover Program (Base Production Optimization):
  • Management expanded the workover program in Q2 2026 after commodity prices improved, targeting low-capital, high-return investments to bring existing production back online and enhance well productivity. These projects have fast payback periods and require only a fraction of the capital needed for a new well, with much shorter timeframes to production.
  • The program complements the core development plan, rather than replacing it, and reflects management's strategy of maximizing value from all existing assets by allocating capital to the highest return opportunities.
• Financial and Risk Management:
  • Stronger realized oil prices and consistent production drove sequential growth in adjusted EBITDA and free cash flow, despite $55 million in net cash hedge losses in Q2.
  • A majority of remaining expected 2026 production is exposed to spot pricing, allowing the company to benefit from sustained commodity price support driven by global supply uncertainty, while the majority of oil hedges are positioned at $65-$70 per barrel to provide meaningful downside protection.
  • The company added new NYMEX WTI roll swaps to manage calendar spread exposure and WAHA basis swaps to reduce West Texas natural gas price fluctuation exposure, with the goal of protecting the balance sheet, preserving cash flow, and maintaining financial flexibility across market conditions.

• Full-year 2026 production guidance is maintained, with first half 2026 production already exceeding the high end of the original guidance range. Management expects production to remain strong through the second half of 2026, with reduced fracking impact on oil volumes compared to Q2 2026.
• Full-year 2026 capital expenditure guidance is maintained; the accelerated completion activity in the first half only shifted the timing of spending, not the total annual budget. Capital spending is expected to decline meaningfully in the second half of 2026, leading to stronger free cash flow generation for the back half of the year. At any reasonable oil price, High Peak expects to generate significant free cash flow in H2 2026.
• Management reaffirms the full-year oil cut guidance range of 67-68%, and expects full-year results to land near the 67% end of the range after the transitory Q2 64% result driven by accelerated completions and workover activity on higher gas-cut older wells.
• The 2027 production and capital setup is expected to be broadly similar to what was planned entering 2026, with two additional drilled uncompleted wells carried into 2027 compared to the original plan due to higher-than-expected drilling efficiency.

High Peak Energy operates as a single upstream oil and gas exploration and production segment, so separate product segment financials are not reported. Aggregate first half 2026 results: average production of 45,500 BOEs per day, unit lease operating expense (LOE) of $7.56 per BOE, total capital spending of $185.9 million, and adjusted EBITDA of $281 million. Second quarter oil weighting was 64%, compared to the full-year guidance range of 67-68%.

• Commodity price volatility: Oil and gas prices are driven by global supply uncertainty, geopolitical events, and interest rates, all of which are outside of the company's control and can impact free cash flow generation and financial performance.
• Natural gas takeaway and pricing risk: Permian Basin pipeline capacity tightness has historically led to significant negative WAHA basis differentials that reduce gas realizations. Management expects further takeaway tightness in late 2027 to 2028, requiring advance preparation.
• Prepayment risk for term debt: Prepaying the term loan beyond required scheduled amortization locks in cash outflows that cannot be recovered, limiting future liquidity if market conditions deteriorate.

Q: What production impact came from pulling forward completion activity into Q2, and what should we expect for H2 2026 production? / A: Pulling four extra completions into Q2 increased frack impacted oil volumes beyond initial projections. Budget totals are unchanged, so 69% of annual completion work was completed in H1, meaning far less frack activity and far less frack impact on production in H2. Drilling will continue with one rig, and one extra well is expected in H2 from ongoing efficiency gains. Production is expected to stay strong for the rest of the year, and High Peak will generate significant free cash flow at any reasonable oil price.

Q: How is management approaching balance sheet liquidity and term loan amortization? Is faster prepayment likely? / A: The required $30 million per quarter amortization will definitely be met starting in Q3 2026. While higher oil prices would generate enough free cash flow to prepay more than the required amount, management will be cautious about excess prepayment because unlike a revolving credit facility, prepaid term loan amounts cannot be re-borrowed. Management will maintain enough cash on hand to weather market variability through 2027 and beyond, with decisions on excess prepayment dependent on quarterly free cash flow driven by commodity prices.

Q: What is the future opportunity for additional workovers, and where do the costs of these programs show up in financial statements? / A: Workovers are mostly performed on wells that already require intervention, rather than taking productive wells offline. Most of the immediate high-opportunity workover candidates already identified by management have been addressed in H1 2026. Going forward, new workover opportunities will arise naturally as existing wells require maintenance, so there will always be a pipeline of opportunities, but their timing cannot be forecast precisely. Most workover costs are recorded in LOE, with only incremental capital expenditures booked for stimulation work that increases well reserves.

Q: Why was Q2 oil weighting lower than guidance, and what should we expect for gas pricing and takeaway in H2? / A: Q2 oil weighting dropped to 64% for two transitory reasons: fracking activity shut in a large volume of high-oil-cut production, and reactivated older higher-gas-cut wells from the workover program offset that shut-in production. Management expects full-year oil weighting to hit 67% at the lower end of guidance. Negative WAHA basis differentials narrowed sharply after the Q2 market stress following the Gulf Coast Express expansion, so gas realizations will improve significantly in H2. Gas takeaway capacity is sufficient for the next 12 months, and while no volumes have been stranded, management is preparing for future capacity tightness in 2027-2028.