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Chord Energy Corp (CHRD)·Q1 2025 Earnings Summary

Executive Summary

  • Q1 2025 delivered strong operations: adjusted diluted EPS of $4.04 vs S&P consensus $3.54 (beat ~14%), adjusted EBITDA exceeded consensus, while revenue was slightly below consensus; GAAP diluted EPS was $3.66 as non-GAAP adjustments (derivatives, affiliate fair value, merger costs) lifted adjusted EPS .*
  • Guidance tweaks: FY25 capex lowered by $30MM to $1.325–$1.415B, FY25 LOE range reduced to $9.20–$10.00/Boe, production taxes reduced, while cash interest raised to $65–$71MM due to March bond issuance and buybacks .
  • Shareholder returns: 100% of adjusted free cash flow returned via buybacks after base dividend; $216.5MM repurchases in Q1 and ~$45MM more in April; leverage ~0.3x and liquidity ~$1.945B support continued repurchases .
  • Operational catalysts: expansion of 4‑mile lateral program (7 planned), first well $1MM under budget; longer laterals expected to lower breakevens by $8–$12/bbl vs 2‑mile wells, supporting capital efficiency and margins .
  • Stock reaction drivers: EPS/EBITDA beat, visible cost improvements (LOE), capital discipline (capex cut), and buyback focus; tempered by macro caution (bias to keep one frac crew if oil stays in the $50s), modest revenue shortfall vs consensus, and higher interest expense .*

What Went Well and What Went Wrong

What Went Well

  • Oil volumes beat the high end of guidance (153.7 MBopd; total 270.9 MBoepd), with adjusted EBITDA $695.5MM and adjusted FCF $290.5MM; LOE at $9.56/Boe was below midpoint guidance .
  • Capital efficiency: FY25 capex reduced by $30MM with unchanged volume guidance; LOE FY25 range lowered, reflecting operational improvements and efficiencies .
  • Strategic progress: first 4‑mile TIL delivered under budget; 4‑mile program expanded (7 spuds planned), with early tracer data showing contribution across the entire lateral; management emphasized resilience and flexibility to moderate activity while maintaining FCF .
    “We benefited from better than modeled well performance, solid cost control, and improved downtime, leading to strong oil production and free cash flow above expectations.” — CEO Danny Brown .

What Went Wrong

  • Revenue vs consensus: S&P revenue consensus of ~$1.18B vs S&P-reported actual ~$1.14B (company-reported oil/NGL/gas revenue $1.103B), a modest miss amid pricing/differentials; GAAP EPS below adjusted due to derivative and other non-cash items .*
  • Macro deterioration: bias to keep one frac crew through year-end if oil stays with a “5 handle,” implying lower 4Q TIL cadence and downshift in oil volumes into Q4 absent a second crew .
  • Interest expense and taxes: cash interest guidance increased on new 2033 notes and buybacks; Q1 production taxes were unusually low (6.8%) due to a nonrecurring stripper-well refund and higher gas mix, with normalization to ~8.5% expected for the rest of the year .

Financial Results

Results vs Prior Periods and Estimates

MetricQ3 2024Q4 2024Q1 2025
Adjusted Diluted EPS (Non-GAAP) ($/share)$3.40 $3.49 $4.04
Diluted EPS (GAAP) ($/share)$3.59 $3.43 $3.66
EPS Consensus Mean* ($/share)$3.78*$2.81*$3.54*
Adjusted EBITDA (Non-GAAP) ($MM)$674.5 $640.1 $695.5
EBITDA Consensus Mean* ($MM)$706.3*$607.2*$648.0*
Total Oil, NGL & Gas Revenues ($MM)$1,121.0 $1,064.3 $1,103.3
Revenue Consensus Mean* ($MM)$1,208.3*$1,039.1*$1,175.9*

Values marked with * retrieved from S&P Global.

Margin Trend

MetricQ3 2024Q4 2024Q1 2025
EBITDA Margin %*52.34%*50.14%*58.50%*
Net Income Margin %*16.70%*15.42%*19.28%*

Values marked with * retrieved from S&P Global.

Revenue Mix

Revenue Component ($MM)Q3 2024Q4 2024Q1 2025
Crude Oil Revenues$1,073.9 $970.4 $956.1
NGL Revenues$30.0 $48.0 $61.3
Natural Gas Revenues$17.1 $45.9 $85.9

KPIs and Operating Metrics

KPIQ3 2024Q4 2024Q1 2025
Oil Volumes (MBopd)158.8 153.3 153.7
NGL Volumes (MBblpd)51.7 51.8 48.1
Natural Gas Volumes (MMcfpd)421.8 410.5 414.5
Total Volumes (MBoepd)280.8 273.5 270.9
Percent Crude Oil (%)56.6% 56.1% 56.7%
LOE ($/Boe)$9.56 $9.60 $9.56
Cash GPT ($/Boe)$2.91 $2.86 $3.03
Cash G&A ($MM)$27.9 $31.2 $28.3
Production Taxes (% of commodity sales)9.0% 8.4% 6.8% (incl. $12.2MM reimbursement)
E&P & Other CapEx ($MM)$329.2 $330.3 $355.4
Gross Operated TILs (count)46 36 30

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
E&P & Other CapEx ($MM)FY25$1,340 – $1,460 $1,325 – $1,415 Lowered (~$30MM)
LOE ($/Boe)FY25$9.40 – $10.40 $9.20 – $10.00 Lowered (range tighter; midpoint to ~$9.60)
Oil Volumes (MBopd)FY25150.3 – 154.8 151.0 – 154.0 Maintained/Narrowed (midpoint ~152.5)
Cash Interest ($MM)FY25$51.0 – $59.0 $65.0 – $71.0 Raised (bond issue, buybacks)
Production Taxes (%)FY258.4% – 8.8% 7.8% – 8.2% Lowered
NGL Realization (% of WTI)FY259% – 19% 10% – 18% Adjusted
Gas Realization (% of Henry Hub)FY2535% – 45% 36% – 44% Adjusted
Cash GPT ($/Boe)FY25$2.65 – $3.15 $2.70 – $3.10 Tightened
Cash G&A ($MM)FY25$97 – $107 $97 – $107 Maintained
Cash Tax (% of Adj. EBITDA)FY253% – 10% 4% – 9% Adjusted
Gross Operated TILsFY25—130 – 150 (~80% WI; ~40% 3‑mile) Added color
Base DividendFY25$1.30/share (raised in Feb) $1.30/share (declared Q1) Maintained

Earnings Call Themes & Trends

TopicPrevious Mentions (Q3 & Q4 2024)Current Period (Q1 2025)Trend
Macro & Activity Level2025–2027 outlook to hold oil volumes flat with $1.4B capex; strong Q1 guide; first 4‑mile lateral planned .Bias to keep one frac crew if oil stays in $50s; decision in Q3; oil cadence down into Q4 without second crew .Cautious, prioritizing capital efficiency.
Long Laterals (3‑/4‑mile)Third-mile productivity factor raised to 100%; first 4‑mile lateral execution .3 wells drilled; first TIL $1MM under budget; 7 4‑mile spuds planned; breakevens $8–$12/bbl lower vs 2‑mile .Accelerating adoption; positive early data.
LOE & EfficiencyLOE below expectations; downtime improvements .FY25 LOE guidance reduced; initiatives in artificial lift, logistics, predictive maintenance .Improving cost structure.
Hedging—Conservative, ≤40% hedged prompt quarter; hedge more at higher prices .Consistent framework.
Portfolio (A&D)DJ Basin divestiture; small Williston bolt‑ons .Marcellus non‑core; maximize value; Williston M&A tougher amid price volatility .Ongoing optimization; disciplined.
Taxes/Regulatory—Q1 production taxes 6.8% (nonrecurring refund; higher gas mix); expect ~8.5% remainder .Normalizing upward.
Tariffs/Midstream—Expect tariff pressure later in year; consolidating contracts; more dual/split connections .Vigilant on costs; optionality improving.
Shareholder Returns75% FCF returns; repurchases rising; base+variable dividend .100% FCF returned via buybacks; additional April repurchases; leverage ~0.3x .Buybacks prioritized.

Management Commentary

  • “Share repurchases comprised the entirety of returns after the base dividend, and we expect continued focus on share repurchases going forward.” — CEO Danny Brown .
  • “At current strip prices, we are inclined to maintain 1 frac crew instead of reinstating the second near year‑end… production impact to 2025 would be negligible; 4Q capital would be much lower.” — CEO Danny Brown .
  • “Oil differentials averaged $2.30 below WTI… NGL realizations 20% of WTI; gas realizations 63% above top‑end of guidance; we anticipate gas prices to soften mid‑year before improving.” — CFO Richard Robuck .

Q&A Highlights

  • Activity/Capital Allocation: With oil in the $50s, the default would be one simul‑frac fleet into 2026; reinstatement of the second crew requires “oil firmly in the 60s” and favorable capital allocation vs buybacks .
  • Oil cadence: Expect flattish 3Q vs 2Q and downshift into 4Q due to fewer TILs unless second frac crew returns late‑year .
  • 4‑mile program rollout: Operational results better than expected; lower torque/drag; cleaning in one run; plan to move swiftly to higher share of long laterals as re‑permitting progresses .
  • LOE/Marketing self‑help: Vendor cost reductions, improved run times on legacy Enerplus wells, consolidation of contracts to better rates .
  • Hedging posture: ≤40% prompt quarter, hedge more at higher prices; balance sheet resiliency is the “great hedge” against cyclicality .
  • Portfolio: Marcellus core to the basin but non‑core to Chord; will maximize value over time; Williston M&A challenged by price volatility (bid/ask spread) .

Estimates Context

  • EPS: Adjusted diluted EPS $4.04 vs S&P consensus $3.54 — beat (~+$0.50, ~14%) driven by stronger oil volumes, cost control, and lower LOE; GAAP diluted EPS $3.66 reflects non‑GAAP adjustments (derivatives, affiliate fair value, merger costs) .*
  • Revenue: S&P revenue consensus ~$$1.18B vs S&P actual ~$1.14B (company-reported oil/NGL/gas revenue $1.103B); a modest miss, with realizations and differentials consistent with guidance ranges .*
  • EBITDA: S&P EBITDA consensus ~$648MM vs S&P actual ~$667MM (company adjusted EBITDA $695.5MM); operational outperformance and favorable gas/NGL realizations contributed .*
  • Implications: Street may raise EBITDA/FCF estimates modestly and lower FY25 LOE/capex assumptions; expect production taxes to normalize higher from Q1’s refund, and cash interest higher post 2033 notes .*

Values marked with * retrieved from S&P Global.

Key Takeaways for Investors

  • EPS/EBITDA beat with tightening cost guidance (LOE, capex) and strong liquidity suggests resilient FCF even at lower prices; buybacks likely remain the dominant return lever near‑term .
  • Management bias to keep one frac crew if oil remains in the $50s implies lower 4Q capital and wedge volumes — a defensive posture that preserves inventory and ROCE .
  • 4‑mile lateral expansion is a structural positive: lower breakevens ($8–$12/bbl vs 2‑mile), improved capital productivity/margins, and potential inventory “re‑rating” over time .
  • Watch cash interest and production taxes: interest guide up ($65–$71MM) post notes; production taxes should revert to ~8.5% for the year after Q1’s refund-driven dip .
  • Gas/NGL realizations benefited from seasonality; expect mid‑year softening before year‑end improvement — monitor realizations and midstream optionality efforts (dual/split connections) .
  • Liquidity (~$1.945B) and leverage (~0.3x) enable opportunistic repurchases/M&A; Marcellus remains a non‑core monetization candidate; Williston M&A could be slower amid price volatility .
  • Near‑term trading lens: focus on buyback cadence, 2Q/3Q oil volumes vs guide, and any Q3 decision on reinstating the second frac crew as catalysts for sentiment and estimate revisions .

Notes:

  • Company Q1 press release and 8‑K (Item 2.02) furnish full financials and reconciliations; adjusted metrics reflect non‑GAAP definitions (derivatives, affiliate changes, merger costs, etc.) .
  • Debt actions: $750MM 6.75% senior notes due 2033 (par) priced March 3; concurrent cash tender for 6.375% 2026 notes — supports higher cash interest guidance and improved liquidity profile .