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COMSTOCK RESOURCES INC (CRK)·Q2 2024 Earnings Summary

Executive Summary

  • Q2 results were pressured by sub-$2 gas: oil and gas sales including hedging fell to $278.2m, adjusted EBITDAX to $166.7m, and adjusted EPS to $(0.20), while hedged operating margin compressed to 61% from 68% in Q1 due primarily to weaker realized prices .
  • Production averaged 1.4 Bcfe/d (+4% YoY), but realized gas price of $1.65/Mcf ($2.12 with hedges) drove a GAAP net loss of $(123)m (GAAP EPS $(0.43)) .
  • 2024 activity toggle intact: Q3 D&C CapEx guided to $135–$185m with the frac “holiday” in Q3 and resumption in Q4; full‑year D&C CapEx maintained at $750–$850m; LOE/G&T unchanged; DD&A higher for the rest of 2024 given low SEC prices; tax deferral now virtually 100% .
  • Strategic positives: Western Haynesville efficiencies (days to TD cut from ~85 to 54), cost deflation emerging (pipe), and Horseshoe laterals expected to save 23% capex per section ($8m) over two 5k’ laterals with comparable performance, supporting medium‑term inventory quality and capital efficiency .
  • Street estimates: S&P Global consensus could not be retrieved in this session; we therefore cannot assess beats/misses versus consensus (SPGI request limit reached).

What Went Well and What Went Wrong

  • What Went Well
    • Western Haynesville operational learning curve: drilling time reduced to as low as 54–56 days (from ~85), potentially enabling an extra well per year on the same rig fleet, with additional efficiency gains expected .
    • Horseshoe lateral concept: initial test is near TD with no problems; management expects 23% cost savings ($8m) vs four 5k’ laterals and similar per‑unit performance to straight 10k’ laterals, expanding ability to convert short laterals into long laterals .
    • Liquidity and hedging: ~$1.2bn liquidity at Q2 end; hedging ramping to ~50% of expected production starting Q4’24 and targeting ~50% for 2025–26, providing downside protection into an improving demand outlook (LNG, power, industrial) .
  • What Went Wrong
    • Pricing headwinds: realized gas price $1.65/Mcf ($2.12 with hedges) pulled hedged operating margin down to 61% (from 68% in Q1) and drove adjusted EBITDAX and operating cash flow down Q/Q .
    • Cost outlier pad: Baker 3‑well pad experienced significant drilling difficulties and multiple sidetracks, lifting D&C $/ft for the quarter; excluding Baker, management believes normalized D&C is ~$1,500/ft, trending lower into H2 as pipe prices fall .
    • Weather/third‑party downtime: Hurricane Beryl‑related outages at third‑party treating facilities impacted July volumes (included in Q3 guidance), highlighting some exposure to midstream power reliability .

Financial Results

MetricQ4 2023Q1 2024Q2 2024
Natural gas & oil sales incl. hedging ($m)$354 $336 $278.2
Adjusted EBITDAX ($m)$244 $230 $166.7
Operating cash flow ($m, excl. WC)$207 $182 $118.1
Adjusted EPS ($)$0.10 $(0.03) $(0.20)
Hedged operating/EBITDAX margin (%)68% 68% 61%
Operating costs ($/Mcfe)$0.81 $0.76 $0.84
Realized gas price ($/Mcf)$2.48 unhedged; $2.51 hedged $2.06 unhedged; $2.40 hedged $1.65 unhedged; $2.12 hedged
Production (Bcfe/d)1.5 1.5 1.4

YoY context (vs Q2 2023):

  • Production: +4% YoY .
  • Natural gas & oil sales incl. hedging: down ~2% YoY due to weaker pricing .

KPIs

KPIQ1 2024Q2 2024
Operated wells turned to sales (count)18 12
Avg IP rate (MMcf/d)27 22
Avg lateral length turned to sales (ft)9,229 8,847
D&C CapEx ($m)256 221
Hedged volume as % of gas26% 28%

Notes:

  • Total revenues in Q2 (incl. gas services) were $246.8m; gas services margin was negative in Q2 given high expenses vs revenue .
  • GAAP net loss and diluted EPS for Q2 were $(123.2)m and $(0.43), respectively; adjusted EPS was $(0.20) .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
D&C CapEx ($m)Q3 2024n/a$135–$185 New item
D&C CapEx ($m)FY 2024$750–$850 $750–$850 Maintained
Leasing capital ($m)Q3–Q4 2024n/a$2–$5 per quarter New detail
Leasing capital ($m)FY 2024$70–$80 +$5–$10 to prior (due to Q2 actuals) Raised modestly
LOE, Gathering & Transportation ($/Mcfe)Q3/FY 2024LOE $0.24–$0.28; G&T $0.32–$0.36 Unchanged Maintained
DD&A ($/Mcfe)H2 2024~$1.30–$1.40 FY view Higher through remainder of 2024 given low SEC prices Raised
Interest expenseFY 2024Slight increase after April notes No further changes Maintained
Effective tax rate & cash taxesFY 202422%–25% rate; defer 98%–100% Expect to defer virtually 100% Increased deferral
Production guidanceFY 2024Provided prior; H2 profile implied by rig/frac plan Unchanged; 4Q24 ~10% YoY lower (timing) Maintained
DividendFY 2024Suspended Suspension maintained Maintained
Hedging policy4Q24–2026Target ~50% hedge Target ~50% hedge; ~50% in 4Q24, ~35% in 2025–26 progressing Maintained/updated progress

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4’23 and Q1’24)Current Period (Q2’24)Trend
Gas macro/realizationsEmphasized sub‑$2 gas, toggled rigs/frac, suspended dividend; hedged 16% in Q4 Realized $1.65 ($2.12 with hedges); hedged 28%; hedged margins compressed to 61% Pricing headwinds intensified; hedge layer improving
Hedging strategyAdded swaps/collars; ~50% target for 4Q’24–2026; ~1/3 hedged for 2025–26 Reiterated ~50% target; ~50% in 4Q’24, building 2025–26 Steadily increasing coverage
Activity/CapEx togglesDropped to 5 rigs; 2 frac crews shifting to ~1.5 in H2; D&C FY $750–$850m Q3 frac holiday (one crew paused), Q3 D&C $135–$185m; crew resumes in Q4 Further near‑term flex; back half ramp
Costs/efficiencyCore D&C ~$1,482/ft in Q4 with deflation signs; Q1 operating cost $0.76/Mcfe Western drilling days 85→54–56; pipe deflation emerging; normalize D&C back to ~$1,400–$1,500/ft ex‑Baker Structural efficiency gains and service cost deflation
Western Haynesville450k+ net acres; early wells encouraging; 2 rigs; added 198k acres in Q1 12 producing wells (6/6 H/B); two 2‑well pads drilled; next 6 wells to sales around year‑end/early Jan Progressing toward development cadence
Horseshoe lateralsIntroduced as a way to eliminate “stranded shorties” laterals First horseshoe spud; expected ~23% cost savings and similar performance to straight 10k’ Early execution; potential inventory upgrade
LNG/data centers/direct salesFraming future LNG/power/industrial demand; exploring direct sales; midstream JV Continued inbound from data centers/utilities; positioning for Gulf Coast demand Expanding downstream optionality
Balance sheet/leverageLiquidity ~$1.0–$1.3bn post‑notes; covenant monitored Liquidity ~$1.2bn; leverage monitored; waiver available if needed; dividend return deferred Stable liquidity; conservative posture
Weather/third‑party outagesn/aHurricane Beryl power losses at third‑party facilities hurt volumes for ~1 week; reflected in Q3 guide Transient headwind in Q3

Management Commentary

  • “As a pure play natural gas producer... the future for the company has never ever been brighter. However, the present challenge is managing through these times with natural gas prices at all‑time lows... Strong financial liquidity of $1.2 billion, the industry's lowest cost structure, no bond maturities until 2029...” — CEO Jay (“Miles”) Allison .
  • “Our realized gas price... averaged $1.65... with hedging, it was $2.12... oil and gas sales... were $278 million... cash flow from operations of $118 million... adjusted EBITDAX $167 million... adjusted net loss $0.20 per share.” — Management summary .
  • “We expect our D&C costs will return to normal levels and remain flat to slightly lower for the next couple of quarters.” — COO Dan Harrison (ex‑Baker pad outlier) .
  • “We... added significantly to our hedge position starting in the fourth quarter of 2024 and extending... through 2026... targeting a hedge level of 50%...” — CEO Jay Allison .
  • “For the third quarter, we expect our D&C CapEx to range between $135 million and $185 million... Full‑year D&C guidance remains $750 million to $850 million... DD&A... expected to be higher through the remainder of the year due to the current low prices.” — VP Finance/IR Ron Mills .

Q&A Highlights

  • Horseshoe lateral adoption: Management expects most short laterals can be converted to long laterals via horseshoe wells; first test near TD with no problems; expected ~$8m savings per section and similar per‑unit performance to 10k’ straight laterals .
  • Cost/efficiency trajectory: Baker pad issues were an outlier; excluding it, normalized D&C ~$1,500/ft with further declines expected as pipe prices fall; Western drilling days reduced from ~85 to 54–56 enabling potential extra well per year on same rigs .
  • Activity toggles: Short Q3 frac holiday; crew resumes early October; levers remain flexible based on gas prices; hedges step up in Q4 to ~50% of volumes .
  • Production trajectory: Q4’24 volumes expected ~10% YoY lower (timing of rig drop and well turn‑in‑lines), then Western Haynesville wells drive uptick exiting Q4/into early Q1’25 .
  • Balance sheet/covenants: Leverage ratio closely monitored; waiver could be obtained if needed; dividend reinstatement depends on deleveraging and sustainable FCF .

Estimates Context

  • S&P Global/Capital IQ consensus for Q2’24 (EPS, revenue, EBITDA) could not be retrieved due to SPGI request limits in this session; we therefore cannot assess beats/misses versus Street consensus. Values retrieved from S&P Global were unavailable in this run.

Key Takeaways for Investors

  • Q2 was cyclical‑price driven: margins compressed and cash generation fell Q/Q despite stable operations; near‑term protection improves as hedges step up into Q4 .
  • Capital discipline intact: Q3 frac holiday and lower Q3 CapEx tighten outspend, with activity resuming in Q4 to position for 2025 .
  • Structural efficiency gains: Western Haynesville drilling times down materially; service cost deflation (pipe) emerging; normalized D&C expected to trend ~$1.4–$1.5k/ft ex‑outliers, supporting better capital efficiency into H2 .
  • Horseshoe laterals are a potential inventory unlock: converting short laterals into long‑lateral economics with ~23% per‑section capex savings could enhance returns and extend inventory depth .
  • 4Q volume cadence matters: minimal Western turn‑in‑lines until late Q4/early Q1’25 and Q3 weather/frac holiday effects suggest softer near‑term volumes, with an early‑2025 inflection as new pads come online .
  • Balance sheet/liquidity cushion remains a backstop (~$1.2bn liquidity) while management prioritizes FCF and deleveraging before shareholder distributions .
  • Medium‑term thesis: advantaged Gulf Coast gas, LNG growth, potential direct sales (incl. data centers), and improving hedge cover support upside torque if gas normalizes toward ~$3.25–$3.50 in 2025–26, aligning with management’s contemplated rig adds .

Appendices

Other Q2 press release: administrative scheduling for Q2 earnings (June 24): release date July 30 and call details; no financial metrics included .