DoorDash Market Share Trends in Europe and Grocery in Q1 2026

Key highlights: Comstock Resources (CRK) Q1 2026 financial results (production trends + cost improvements)

1) Production trend: lower in Q1, with improvement expected in coming quarters

• Q1 production came in lower than 2025, and management attributed the decline partly to production impact from significant winter weather during the quarter. ¹
• Average Q1 production was 1.1 Bcfe per day. ²
• Management emphasized that very strong drilling results are expected to drive production back up for the remainder of the year, noting that almost all wells returned to sales were late in Q1 (so the production impact shows up later). ¹
• New Western Haynesville wells added to production: since the prior update, the company put six new Western Haynesville wells online with an average initial production rate of 29 MMcf/d per well. ¹
• Looking forward, management said production should increase ~13–15% in Q2 (their expectation for sequential rebound after the Q1 shortfall). ³
• Management further characterized the situation as “turning the curve” after production down and CapEx up, stating the added frac fleet supports the recovery. ⁴

2) Financial performance highlights tied to the production level and hedging

• Oil and gas sales after hedging were $339 million in Q1, reflecting the lower production level. ¹
• Operating cash flow was $192 million (and $0.66 per share). ¹
• Adjusted EBITDAX was $251 million, and adjusted net income was $44 million ($0.15 per share). ¹
• Reported earnings included items that management separated for “adjusted net income”:
  • Management reported $107 million profit ($0.38 per share) but said it included a pretax $83 million mark-to-market unrealized gain related to the hedge book. ²
  • Management also referenced excluding exploration expense (seismic) and other nonrecurring items (and their related tax effects) to arrive at adjusted net income of $44 million. ²
• Pricing/hedging context:
  • Q1 weighted average NYMEX settlement was $4.96, and Henry Hub spot was $4.90. ²
  • Realized gas price averaged $4.27, reflecting basis differentials vs NYMEX and an additional factor from the winter period (purchased higher-priced gas to make up for shut-in production during the winter storm event). ²
  • The company stated it was 72% hedged in the quarter, which reduced realized price to $3.45, though it also said third-party gas sales improved overall realizations by $0.05 to $3.50. ²

3) Capital spending and well activity: drilling intensity continued despite Q1 production shortfall

• Management reported $343 million spent on the drilling program in Q1. ⁵
• Well count (Q1):
  • 11 (9.3 net) horizontal Haynesville wells and 6 (6 net) Bossier wells for 17 total wells (15.3 net). ⁵
  • 13 wells turned to sales (11.7 net) with overall average per-well initial production (IP) rate of 31 MMcf/d. ⁵
• Balance sheet/liquidity context: at quarter-end, the company had $1.3 billion of liquidity and $350 million of borrowings under its upstream credit facility, with an upstream borrowing base of $2 billion and elected commitment of $1.5 billion. ⁵

4) Cost improvements / cost discipline: what changed in Q1 (and why)

Even though some unit costs rose in Q1 (because much of the cost base is fixed when production is temporarily lower), management highlighted operational initiatives expected to reduce costs and improve drilling efficiency.

A) Operating cost per Mcfe: higher in Q1 due to lower volumes (fixed-cost effect)

• Management stated operating cost per Mcfe averaged $0.93 in Q1, up $0.16 vs the Q4 run-rate, and that this was negatively impacted by the lower production level because many field costs are fixed. ⁵
• They also said lifting cost and G&A were up $0.04, tied to lower production, while production ad valorem taxes increased $0.03 and gathering costs were up $0.05 due to prior period adjustments recognized. ⁵
• Despite that, EBITDAX margin was 73% in Q1. ⁵

B) Drilling and completion cost trends (per-foot): improvements mainly in completion costs

Legacy Haynesville benchmark (per foot):

• Drilling cost averaged $700/foot, up 3% vs Q4, with the increase attributed to a mix of factors including shorter average lateral length, more wells drilled, and more East Texas area wells (requiring additional casing for SWD isolation). ⁶
• Completion cost averaged $652/foot, down 9% vs Q4, attributed to less horsepower, higher frac efficiency, and a slightly lower drill-out cost. ⁶

Western Haynesville development (per-foot D&C):

• Western Haynesville drilling cost averaged $1,534/foot, up 3% vs Q4. ⁷
• Western Haynesville completion cost averaged $1,537/foot, described as basically unchanged vs Q4. ⁷
• Management emphasized performance variability because costs depend on where wells are drilled (vertical depth, temperatures, and lateral lengths). ⁷

C) Structural cost actions underway: higher-speed drilling and execution initiatives

• Western Haynesville rig upgrade: one existing Western Haynesville rig is being upgraded to a 10,000 PSI rating, expected available by late summer, with management expecting this to increase drilling speeds in vertical and horizontal sections to reduce cost. ⁷
• They also said they intend to test new higher-temperature rated drilling motors later in 2026, expecting faster drill times and longer runs. ⁷
• Technology adoption: management indicated that once they see more successful and consistent runs of rotary steerable drilling in the legacy Haynesville area, they may deploy it into Western Haynesville as well to support cost reductions. ⁷
• On the frac fleet schedule, management said they were running three full-time frac fleets after adding the third in January, and they are adding a fourth frac fleet “this month” and planning to maintain four through the end of the year. ⁶
  • While the excerpts do not quantify the cost-per-unit impact directly, the operational point is that the company is adding execution capacity to improve throughput and production recovery. ⁶

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Bottom line

• Q1 2026 was a reset quarter: production was down (partly winter-driven), which pressured sales and many per-unit metrics, even though adjusted EBITDAX and adjusted net income were reported and cash generation remained meaningful. ¹²
• The operational rebound is being engineered through execution: management pointed to strong drilling results and new wells added online plus expectations for production growth ~13–15% in Q2. ¹³
• Cost progress is visible in parts of the cost stack: completion costs improved notably in legacy benchmarks (down 9% per foot vs Q4), and management is also pursuing rig upgrades, motor testing, and technology refinement aimed at further cost reductions going forward. ⁶⁷