Comstock Resources, Inc. Q2 FY2026 earnings call

• Transaction and Balance Sheet Updates

  • Completed a minority equity sale of 27% of Pinnacle Gas Service (midstream subsidiary) to Sixth Street funds for $600 million on June 15, 2026, implying a $2.2 billion total enterprise value for PGS. The transaction validates the value of Comstock's Western Hainesville natural gas position, which is strategically located to serve growing Gulf Coast natural gas demand and the newly announced Texas Power Generation Hub in Anderson County, Texas.
  • The transaction eliminated all of Pinnacle's outstanding debt and preferred equity, strengthening Comstock's consolidated balance sheet. Comstock retains 73% controlling equity interest (increasing to 80.5% after return hurdles are met) and full operational control of PGS to support Western Hainesville growth. Total corporate liquidity at quarter-end was ~$1.2 billion, with a last twelve months leverage ratio of 3.0x.

• Acreage and Drilling Inventory

  • Total prospective acreage in the Hainesville-Bossier play is 1,078,228 gross acres / 809,244 net acres. Western Hainesville now holds 545,000 net acres, with legacy Hainesville holding 264,000 net acres.
  • Legacy Hainesville has 717 net operated drilling locations (926 gross) and 99 net non-operated locations (779 gross), with 50% of gross operated locations having laterals over 10,000 feet and an average lateral length of 10,153 feet. The inventory is evenly split between Hainesville and Bossier formations, including 113 gross Horseshoe U-turn well locations.
  • Western Hainesville has 2,528 net operated drilling locations (3,277 gross), with no short laterals under 5,000 feet, 40% of gross locations over 10,000 feet, and an average lateral length of 8,875 feet. Two-thirds of the inventory is in the Bossier Formation and one-third in Hainesville.

• 2026 YTD Drilling and Well Performance

  • As of Q2 2026, 11 Western Hainesville wells and 22 legacy Hainesville wells (including 8 Horseshoe wells) have been turned to sales, both with an average initial production (IP) rate of 31 million cubic feet per day. Average lateral length was 10,331 feet for Western Hainesville wells and 12,052 feet for legacy Hainesville wells. 41 Western Hainesville wells are currently producing, with 13 more in development.
  • In Q2 2026, legacy Hainesville long lateral (>8,500 foot) wells averaged 24 days to total depth, a 10% improvement in drilling speed (1,017 feet per day) over Q1 2026, with 6 of 13 wells being Horseshoe wells. Western Hainesville drilling speed dipped 2% sequentially to 469 feet per day, driven by 1,200 feet deeper average true vertical depth (TVD) and higher downhole temperatures.

• Drilling and Completion (D&C) Costs

  • Legacy Hainesville long lateral wells: Q2 2026 average drilling cost was $710 per foot (flat +1% sequentially), and average completion cost was $680 per foot (+4% sequentially) driven by longer drill outs and higher flowback costs.
  • Western Hainesville wells: Q2 2026 average drilling cost was $1,738 per foot (+13% sequentially) driven by steering difficulties and extra trips, offset partially by the first Big Hole Lateral well drilled at $1,306 per foot (25% below the quarter average). Average completion cost was $1,609 per foot (+5% sequentially) driven by higher proppant loading and more single-well pads.

Comstock Resources operates as a single upstream oil and gas exploration and production segment, with a separate midstream segment (Pinnacle Gas Service, PGS). For Q2 2026: upstream production averaged 1.2 BCFE per day, up 16% quarter-over-quarter and 1% year-over-year. Total natural gas and oil sales including realized hedging gains were $332 million. Adjusted EBITDA (EBITDAX) was $245 million, operating cash flow excluding working capital changes was $189 million (65 cents per share), and net profit was $9 million ($0.03 per share). Adjusted net income excluding non-recurring items was $8 million ($0.03 per share). Year-to-date (H1 2026): total oil and gas sales were $670 million, EBITDAX was $496 million, operating cash flow was $380 million, and reported net profit was $116 million (40 cents per share); adjusted net income excluding non-recurring items was $48 million (16 cents per share). Following the sale of a 27% non-controlling stake in PGS to Sixth Street for $600 million, PGS is now 100% debt-free, with Comstock retaining a 73% controlling stake that implies an enterprise value of $1.6 billion for Comstock's holding, and PGS generates $40 million in annual fixed charge savings from debt elimination.

• Full year 2026 production guidance maintains the prior expectation that Q4 2026 production will return to the peak levels seen in early 2024, with sequential production growth expected in both Q3 and Q4 2026 at similar rates.
• 2026 drilling plans are unchanged: 4 operated rigs running in Western Hainesville targeting 22 wells drilled and 21 wells turned to sales; 5 operated rigs running in legacy Hainesville targeting 48 wells drilled and 48 wells turned to sales, with 16 total Horseshoe wells drilled and 17 turned to sales for the full year.
• 2027 activity levels have not been finalized; management will make a final decision on 2027 drilling activity later in 2026, and will require stronger, hedgeable natural gas prices to support sustained high activity levels. The company's core strategic goal is to continue de-risking the Western Hainesville play and be positioned to scale rapidly when expected natural gas demand growth materializes.
• Technology deployment timeline: The first 10,000 PSI rig will be deployed in Western Hainesville in Q4 2026 to improve drilling speeds, with additional rig upgrades expected if the first deployment is successful. Higher temperature rated downhole drilling motors will be tested in Western Hainesville in Q4 2026. Development of a 20,000-pound high-pressure frac spread is targeted for 2027.

• Western Hainesville drilling is still in the early appraisal and optimization phase, with new technology and design changes still being tested; performance and cost improvements from new designs (Big Hole Lateral, higher temperature motors) have only been demonstrated on one initial well, and repeatability across multiple wells has not yet been confirmed.
• Current natural gas prices are lower than management expected entering summer 2026, which creates uncertainty about 2027 capital spending and drilling activity levels.
• Western Hainesville drilling is currently constrained by the need to hold existing older leases by production, which means the current drilling program is not always able to target the most optimal well locations or fully implement longer lateral designs preferred by management.
• Higher proppant loading for larger frac jobs increases completion costs, and the expected increase in estimated ultimate recovery (EUR) from larger fracks has not yet been confirmed via long-term production performance.
• Deeper drilling in Western Hainesville leads to higher downhole temperatures, which reduce downhole tool service life, increase the number of trips required, and slow drilling speeds while raising costs.

Q: With the D&C optimization efforts underway in Western Hainesville, including new big hole designs and higher-spec equipment, where do well costs trend once all improvements are implemented? / A: Management expects drilling costs to decline materially with the big hole lateral design, which has already delivered a 25% cost discount on the first well compared to existing slim hole designs. Better steering, fewer course correction delays, and lower downhole temperatures from improved mud circulation will make well performance more predictable as well as cheaper. Completion costs will rise moderately due to larger, higher proppant fracks that management expects will increase well productivity. Overall total D&C costs are expected to stay roughly flat to slightly lower than current levels after all changes are implemented. / Q: What productivity improvements are expected from the new big hole lateral design, beyond lower drilling costs? / A: The larger internal diameter of big hole laterals reduces pipe friction and treatment pressure, allowing faster pumping, higher frac efficiency, and enables longer laterals than are feasible with smaller slim hole designs. Management emphasized that Western Hainesville is the emerging major natural gas field positioned to serve growing LNG and data center demand near the Texas Gulf Coast, and ongoing incremental technology improvements are de-risking the play for long-term growth. / Q: Why are Horseshoe U-turn wells in legacy Hainesville consistently delivering strong IP rates, beyond accessing stranded acreage? Is there a technology or design driver? / A: Horseshoe wells do not use a different completion design than standard long lateral wells; strong performance is mostly driven by their location in high-quality core legacy Hainesville areas that could not be economically developed with shorter conventional wells. Rotary steerable drilling technology has made it possible to drill the 180-degree U-turn efficiently with minimal delays, unlocking 113 new economic locations that were previously undeveloped. Early results from the first Texas Horseshoe well are pending, but all Louisiana Horseshoe wells have met or exceeded expectations. / Q: How will 2027 production growth look if the current 9-rig program continues, and will you hold back activity if natural gas prices stay low? / A: Management has not finalized 2027 activity levels, and will wait until late 2026 to make a final decision based on natural gas price levels and the ability to hedge production at attractive prices. The company's core priority is to continue de-risking the large Western Hainesville resource base to be ready to rapidly scale production when expected natural gas demand growth from LNG and power generation materializes, with no plans to pause long-term development.