Comstock Resources' Q3 2025: Contradictions Emerge on Choke Management, Capital Efficiency, and Acreage Development

Date of Call: November 4, 2025

Financials Results

• Revenue: $335.0M, up 10% YOY (Q3 2025 vs Q3 2024)
• EPS: $0.09 per diluted share (adjusted), adjusted net income $28M vs a loss in Q3 2024

Guidance:

• Continue Western Haynesville build-out with 4 operated rigs; expect 19 wells drilled and 13 wells turned to sales in Western Haynesville in 2025.
• Legacy Haynesville: expect to drill 33 (25.6 net) wells and turn 35 (28.2 net) wells to sales in 2025.
• Marquez Phase 2 planned (capacity expansion) with long‑lead items ordered; target online timing ~next summer.
• Continue midstream buildout; Shelby Trough sale expected to close in December to reduce debt and improve liquidity (> $900M).

Business Commentary:

• Financial Performance and Growth:
• Comstock Resources reported oil and gas sales of $335 million in Q3 2025, up 10% compared to the previous year, with operating cash flow of $190 million.
• 

• The growth was mainly driven by higher natural gas prices, which increased by 18% year-to-date.

• Divestitures and Strategic Focus:

• Comstock announced the divestiture of non-strategic assets, including the sale of Cotton Valley wells for $15.2 million and Shelby Trough assets for $430 million.

• The divestitures were part of a strategic shift to focus resources on the Western Haynesville acreage, improving the balance sheet by retiring long-term debt.

• Western Haynesville Development and Inventory:

• The company reported 2,559 net locations in the Western Haynesville, indicating significant potential for future drilling and production growth.

• This inventory is driven by the Western Haynesville's favorable geology and the company's strategic acquisition of acreage over the past five years.

• Operating Cost Efficiency:

• Comstock's operating costs per Mcfe averaged $0.77 in Q3 2025, a decrease of $0.03 from the previous quarter, maintaining a 74% EBITDAX margin.
• Cost reductions were achieved through improvements in lifting costs, gathering and cash G&A costs, and reduced production and ad valorem taxes.

Sentiment Analysis:

Overall Tone: Positive

• "I don't believe we have ever seen a brighter future for natural gas." Management highlighted $190M of operating cash flow, adjusted EBITDAX of $249M, plans to expand Western Haynesville inventory and midstream (Marquez Phase 2), and >$900M liquidity with Shelby Trough proceeds to reduce debt.

Q&A:

• Question from Derrick Whitfield (Texas Capital Securities): Could you speak to the broader capital efficiency gains you'd expect entering 2026 given higher activity and operational efficiencies in both Western and legacy Haynesville?
  Response: Legacy is near peak efficiency (horseshoe wells); Western Haynesville still on a learning curve with ongoing improvements, and carrying an added rig this year should materially improve capital efficiency in 2026.

• Question from Derrick Whitfield (Texas Capital Securities): How do you see gas-on-gas competition along the Gulf Coast and Comstock's supply advantage serving both LNG and power/gen markets?
  Response: Owning Western Haynesville midstream and favorable location near LNG and power demand allows direct sales to end users and better capture of value versus third-party midstream.

• Question from Charles Meade (Johnson Rice & Company): How would you characterize the Shelby Trough sale and are there other assets that could fetch similar prices from buyers of undeveloped locations?
  Response: The Shelby Trough sale was a win-win: strong proceeds used to pay down debt; management will continue evaluating non-core divestitures but focus remains on derisking and funding Western Haynesville development.

• Question from Charles Meade (Johnson Rice & Company): Can you walk through key assumptions behind the ~2,500–2,600 Western Haynesville location count and the impact of unitization on that number?
  Response: Assumptions are conservative on spacing and zones; Western net counts are estimates because units are still being formed, but management believes the disclosed net number is within a reasonable margin of error.

• Question from Kaleinoheaokealaula Akamine (BofA Securities): What stops you from doing land work to optimize the Western position around 10,000-foot laterals and how long would that take?
  Response: Ownership fragmentation, other operators' acreage and geologic/ seismic constraints force some shorter laterals now; optimization and additional leasing/unitization can be done over time but will be incremental.

• Question from Kaleinoheaokealaula Akamine (BofA Securities): Was Marquez Phase 2 part of the original JV scope with Quantum; what's current capacity/utilization and timeline for Marquez 2?
  Response: Marquez Phase 2 was in the original plan to scale treating capacity (targeting multi-Bcf gross over time); long‑lead equipment is being procured and the goal is to come online around next summer, utilization forecasts were not provided.

• Question from Carlos Andres E. Escalante (Wolfe Research): Given leasing/M&A activity nearby, could the core extend further and what's the status of the permitted well near Olajuwon?
  Response: Core may expand and outside activity can be value-accretive; a 2‑well pad near Olajuwon was spud last week (Haynesville plus a first Bossier test) and coring is underway.

• Question from Carlos Andres E. Escalante (Wolfe Research): Any collaboration/learning opportunities from nearby operators with strong type curves?
  Response: There have been acreage swaps and operator activity is helpful; peer activity shortens the basin learning curve and provides valuable operational insights.

• Question from Kevin MacCurdy (Pickering Energy Partners): Any color on how you plan to prosecute Western Haynesville in 2026 — holding acreage vs development, pad sizes, lateral lengths and where you'll drill?
  Response: Primary objective is to hold leased acreage; four rigs in Western are sufficient to hold positions and delineate the play, with drilling locations driven by lease terms and where they need to hold acreage.

• Question from Kevin MacCurdy (Pickering Energy Partners): Were changes in legacy Haynesville/Bossier inventory driven solely by asset sales or anything else?
  Response: Changes reflect breaking out Western inventory, removal of sold acreage (Shelby Trough/Cotton Valley), and ongoing recalibration as average lateral lengths increase.

• Question from Jacob Roberts (Tudor, Pickering, Holt & Co.): Can you describe the choke management experiments in Western Haynesville on recent TILs and planned approaches for upcoming wells?
  Response: Management varied approaches across recent wells; early analysis favors more conservative drawdown, and they plan to transition toward that conservative approach going forward.

• Question from Jacob Roberts (Tudor, Pickering, Holt & Co.): How do you view the evolving industrial market (long‑term contracts) and Comstock's willingness to participate in industrial agreements at premiums?
  Response: Management sees growing interest from industrial end users for long-term supply and is open to pursuing direct, long-term agreements to capture more value versus selling into the spot/index markets.

• Question from Phillips Johnston (Capital One Securities): Would you expect any tax leakage on the gross proceeds from the Shelby Trough sale?
  Response: Expect a sizable book gain but limited cash tax impact because the company has tax attributes available to offset taxes; details to appear in the 10‑Q.

• Question from Phillips Johnston (Capital One Securities): How many wells might be planned in the northern Olajuwon/step-out area for next year?
  Response: Management indicated approximately 5–6 wells planned in that northern step‑out area for next year as they test Bossier and develop the bench.

• Question from Noel Parks (Tuohy Brothers Investment Research): Have you studied in‑house treating economics vs third‑party while ramping up Marquez and how do economics compare?
  Response: Owning treating infrastructure requires capital recovery but yields much lower operating costs and better long‑term economics and value capture once capacity is utilized; partnership funding reduces strain.

• Question from Noel Parks (Tuohy Brothers Investment Research): Was gathering & transportation expense down sequentially and what drove that change?
  Response: Yes — G&T expense was down slightly sequentially driven primarily by lower volumes; G&T per unit was ~$0.36 vs $0.37 in prior quarter.

• Question from Paul Diamond (Citigroup Inc.): If you add activity over time (currently ~50/50 Western vs legacy), where would incremental activity come from?
  Response: Management prefers to keep four rigs steady in Western to hold acreage and will flex legacy activity responsively to market supply/demand and price, so incremental activity would be allocated based on those dynamics.

• Question from Paul Diamond (Citigroup Inc.): Do D&C costs still track toward roughly $30M per 10,000‑ft well and what's the longer‑term target?
  Response: They expect D&C costs to continue declining but vary by depth/location; ~$30M per 10,000‑ft is a reasonable reference but deeper locations can be modestly higher and costs will continue to be optimized.

Contradiction Point 1

Choke Management and Production Rates in the Western Haynesville

It involves differing explanations of the purpose and expected outcomes of choke management strategies in the Western Haynesville, which could impact production rates and company performance.

How is choke management experimentation in the Western Haynesville affecting production rates? - Jacob Roberts (Tudor, Pickering, Holt & Co. Securities)

2025Q3: We continue to experiment with choke management and have seen an increase in production rates as a result. - [Daniel S. Harrison](COO)

Why are you testing restricted choke management in the Western Haynesville, and is it based on data or competitive actions? - Derrick Lee Whitfield (Texas Capital Securities)

2025Q2: The testing is due to the deep and hot nature of the area and pressure-dependent perm effects. It aims to achieve more disciplined drawdowns and potentially better EURs in the long run. - [Daniel S. Harrison](COO)

Contradiction Point 2

Capital Efficiency and Cost Trends in the Western Haynesville

It involves differing explanations of capital efficiency gains and cost trends in the Western Haynesville, which could impact development and financial strategy.

How do you expect capital efficiency gains in Western and legacy Haynesville areas with increased 2026 activity? - Derrick Whitfield (Texas Capital Securities)

2025Q3: We're seeing some very positive initial results on the West side with 10,000-foot laterals, which are drilling 30% to 40% faster and $4 million to $5 million per well cheaper than the 7,500-foot laterals. - [Miles Jay Allison](CEO)

What are the key takeaways from drilling the Olajuwon step-out well in the Western Haynesville? How does shallower drilling impact costs and the local capital cost trend? - Carlos Andres E. Escalante (Wolfe Research, LLC)

2025Q2: Drilling times and costs are highly variable, and newer completions have helped improve production. - [Daniel S. Harrison](COO)

Contradiction Point 3

Capital Allocation and Acreage Development

It involves differing strategies and priorities for capital allocation between holding acreage and development, which directly impacts the company's growth trajectory and resource utilization.

What are your plans for Western Haynesville next year, and how do you plan to balance acreage retention with development? - Kevin MacCurdy (Pickering Energy Partners Insights)

2025Q3: So acreage to hold will be prioritized in the Western Haynesville. - [Roland Burns](CFO)

What are your assumptions for capital allocation between HBP wells and delineation wells in 2026? - Carlos Escalante (Wolfe Research)

2025Q1: In the Legacy Haynesville, drilling will be price-driven and takeaway considerations will influence location. - [Roland Burns](CFO)

Contradiction Point 4

Drilling and Completion Cost Savings

It reflects differing opinions on the potential for cost savings in drilling and completion expenses, which are crucial for operational efficiency and profitability.

How do you expect capital efficiency to improve in the Western and legacy Haynesville areas with increased 2026 activity? - Derrick Whitfield (Texas Capital Securities)

2025Q3: We are seeing -- we saw $200 a foot decreases in drilling costs on the eight wells drilled in the third quarter. The executives think you're going to see that trend continue. - [Roland Burns](CFO)

How will CapEx per well trend, and how will you achieve cost savings in completions and address drilling challenges? - Carlos Andres E. Escalante (Wolfe Research)

2024Q4: I think we have more room to probably or our cost on the drilling side. I mean, we've seen a bigger drop on the drilling side than the completion side. I think we have room to lower the completion cost a little. Q4 cost we have in there at $1,315 a foot, that's kind of a number that we're planning with for the future wells just for forecasting. - [Daniel Harrison](COO)

Contradiction Point 5

Western Haynesville Infrastructure Growth

It involves differing statements about the timeline and expectations for infrastructure growth in the Western Haynesville, which impacts operational efficiency and production capacity.

Could you provide details on the capacity utilization of the second train at the Marquez gas plant as it comes online? - Kaleinoheaokealaula Akamine (BofA Securities)

2025Q3: We're on a good pace, the wells in the footprint are ready to be completed in the first quarter. - [Dan Harrison](COO)

Does hiring the spot crew indicate the full-year production guidance’s upper half remains achievable? - Kalei Akamine (Bank of America)

2025Q1: We're in the second quarter and we'll produce more than 1.15 this year. - [Jay Allison](CEO)