COMSTOCK RESOURCES INC (CRK)·Q1 2024 Earnings Summary

Executive Summary

• Q1 2024 results were pressured by weak gas prices: total revenues fell to $335.8M, diluted EPS was $(0.05), and adjusted EPS was $(0.03); hedged operating margin held at 68% despite lower realized prices .
• Liquidity strengthened via $100.5M private placement to the majority stockholder in March, a $400M senior notes offering in April, and reaffirmed $2.0B borrowing base; pro forma liquidity reached ~$1.3B .
• Western Haynesville continued to deliver strong well results (35–38 MMcf/d IP), and Comstock added 198K net acres (now >450K net) largely HBP, enabling a measured development pace through low-price conditions .
• Guidance: Q2 D&C CapEx $200–$250M; FY D&C CapEx unchanged at $750–$850M; lease acquisition outlook raised to $70–$80M for FY; cash interest expense tweaked higher post notes; tax deferral expectation increased to 98–100% .
• Near-term stock catalysts: continued Western Haynesville well performance and cost reductions, hedge additions through 2026 (~1/3 hedged for 2025–2026; ~50% in Q4’24), and disciplined activity/turn-in-line timing to optimize realizations in a “weak spot price” environment .

What Went Well and What Went Wrong

• What Went Well

  • Strong Western Haynesville well IPs and expanding footprint: four Haynesville wells with 35–38 MMcf/d IP; acreage increased by 198K net to >450K net, mostly HBP, supporting long-term inventory and controlled development .
  • Cost discipline and margin resilience: production cost per Mcfe fell to $0.76; hedged operating margin held at 68% despite lower prices; EBITDAX margin after hedging was 68% .
  • Balance sheet and liquidity actions: $100.5M equity infusion from Jones family, $400M 2029 notes, $2.0B borrowing base reaffirmed; pro forma liquidity ~$1.3B .

• What Went Wrong

  • Pricing headwinds drove GAAP and adjusted losses: realized gas price fell to $2.06/Mcf (incl. hedging $2.40), total revenues declined to $335.8M, GAAP diluted EPS $(0.05), adjusted EPS $(0.03) .
  • Gas services margin turned negative in Q1: gas services revenue $47.8M vs expenses $48.7M, margin $(0.9)M versus positive margins in prior quarters .
  • Higher DD&A and interest burden: DD&A rose vs prior year; cash interest expense guide increased modestly post April notes offering .

Financial Results

Headline metrics vs prior year and prior quarter

Prices and realizations

Production and costs

Segment/line-item breakdown

Balance sheet (selected)

Guidance Changes

Earnings Call Themes & Trends

Management Commentary

• “We’ve been very active… with all hands focused on continuing to batten down the hatches… during this weak period for natural gas.” — CEO Jay Allison .
• “We added 300 MMcf/d of swaps Oct 2024–Dec 2026 at ~$3.51/Mcf… about 1/3 hedged for 2025 and 2026.” — CFO Roland Burns .
• “Latest four Western Haynesville wells… had IP rates of 35 to 38 MMcf per day.” — CEO Jay Allison .
• “Our operating costs averaged $0.76 per Mcfe… EBITDAX margin after hedging came in at 68%.” — CFO Roland Burns .
• “Our bank lending group reaffirmed the $2.0 billion borrowing base… [and] we issued $400 million of additional senior notes due in 2029.” — CFO Roland Burns .

Q&A Highlights

• Western Haynesville economics vs core Haynesville: management sees similar returns with higher EURs per 1,000’ offsetting higher costs; pacing flow rates conservatively given low prices; costs are trending down as learnings compound .
• Activity needed to HBP: ~95% of recently acquired 198K net acres are HBP; no pressure to add rigs in low-price environment; pad development strategy to efficiently HBP remaining acreage over years .
• Customer diversification and data centers: interest from data centers and other direct customers; midstream JV to support tailored infrastructure; aim to reduce sales to aggregators .
• Operational flexibility: ability to toggle rigs/frac crews, strategically delay turn-in-lines/shut-ins to avoid unfavorable spot prices; no long-term frac commitments .
• Core short laterals and “horseshoe” design: plan to eliminate stranded short laterals by experimenting with horseshoe wells; expect fewer short laterals going forward .

Estimates Context

• Wall Street consensus (S&P Global) for Q1 2024 EPS/revenue was unavailable due to data access limits at time of analysis, so beats/misses vs consensus cannot be shown here. S&P Global estimates could not be retrieved (API daily limit exceeded).
• Given realized price pressure and hedging uplift, we expect near-term estimate adjustments to focus on price realizations, cost deflation trajectory, and Western Haynesville pacing. If consensus becomes available, revisit comparisons and highlight any surprises.

Key Takeaways for Investors

• Hedging extended through 2026 with meaningful floors (~$3.50), providing downside protection and improving cash flow visibility; ~50% hedged in Q4’24 and ~1/3 in 2025–2026 .
• Western Haynesville is emerging as a multi-decade growth asset: strong IPs (35–38 MMcf/d), improving drill times (to 54 days), and majority HBP acreage support capital-efficient scaling when prices improve .
• Cost performance is a differentiator: production costs fell to $0.76/Mcfe and hedged operating margins held at 68% despite weak prices, underpinning resilience vs peers .
• Liquidity actions de-risk the balance sheet: $100.5M equity, $400M notes, and $2.0B borrowing base reaffirmation result in ~$1.3B pro forma liquidity, enabling flexible activity management through a weak gas tape .
• Near term, expect disciplined rig/frac cadence and timing of turn-in-lines to manage realizations; medium term, LNG corridor demand and potential data center offtake could accelerate value recognition .
• Watch for Q2 execution vs guidance (D&C $200–$250M) and FY lease acquisition spend ($70–$80M) updating footprint while preserving cash generation .
• Gas services margin dipped negative in Q1; monitor midstream JV funding cadence and margin trends as Western Haynesville volumes ramp .