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BS

Black Stone Minerals, L.P. (BSM)·Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 was operationally soft on volumes but financially strong on GAAP due to a sizable unrealized hedge gain; oil & gas revenue fell 6% sequentially to $102.0M while net income surged to $120.0M on a $52.8M derivative gain .
  • The Partnership cut the quarterly distribution 20% to $0.30, citing slower-than-expected gas-weighted activity; coverage rose to ~1.18x, with total debt reduced to $71.0M by August 1 on stronger cash generation .
  • 2025 total production guidance was lowered to 33–35 MBoe/d from 38–41 MBoe/d, reflecting delayed gas activity, but management sees a multi-year ramp from new Shelby Trough development agreements and expects production to grow in 2026 with potential to surpass prior distribution highs over the next six years .
  • Versus S&P Global consensus, Q2 revenue and EPS missed: revenue $102.0M vs $112.6M and Primary EPS 0.2794* vs 0.325; the miss was driven by lower volumes despite supportive commodity prices; EBITDA was broadly in line depending on definition (company Adjusted EBITDA $84.2M) .
  • Near-term stock narrative hinges on the lowered 2025 guide and distribution cut vs the structural growth story from Revenant and marketed acreage that more than doubles development obligations over five years; Investor Day in September is a potential catalyst .

What Went Well and What Went Wrong

What Went Well

  • Hedge mark-to-market drove GAAP strength: $52.8M derivative gain (including $49.6M unrealized), lifting net income to $120.0M from $15.9M in Q1 .
  • Adjusted EBITDA held resilient at $84.2M despite lower volumes and realized prices, essentially flat sequentially (+2% q/q) .
  • Strategic positioning in Shelby Trough expanded: Revenant agreement covering ~270,000 gross acres with obligations ramping from 6 wells in 2026 to 25 per year over five years; additional ~180,000 gross acres being marketed to push west toward Western Haynesville .
  • “Through these new areas and the existing Shelby Trough agreements, we see contractual development obligations more than doubling over the next five years.” — Thomas L. Carter, Jr. .

What Went Wrong

  • Volumes slipped: mineral & royalty production fell to 33.2 MBoe/d (−3% q/q, −13% y/y); total production 34.6 MBoe/d (−3% q/q, −14% y/y) .
  • Distribution cut: $0.30 per unit (−20% q/q) as slower gas-weighted activity and delayed ramps pressured near-term cash generation; coverage improved to ~1.18x .
  • 2025 guide reset: total production guidance lowered to 33–35 MBoe/d (from 38–41); management cited Aethon cadence changes and timing to spool multiple operators and infrastructure before ramping activity .

Financial Results

Headline Financials (vs prior periods)

MetricQ2 2024Q1 2025Q2 2025
Oil & Gas Revenue ($USD Millions)$110.4 $108.3 $102.0
Revenue from Contracts ($USD Millions)$115.2 $115.3 $106.7
Total Revenue incl. Derivatives ($USD Millions)$109.6 $59.3 $159.5
Net Income ($USD Millions)$68.3 $15.9 $120.0
EPS per Common Unit (Basic/Diluted) ($)$0.29 $0.04 $0.53
Adjusted EBITDA ($USD Millions)$100.2 $82.2 $84.2
Distributable Cash Flow ($USD Millions)$92.5 $73.7 $74.8

Margins (SPGI-defined; impacted by derivative swings)

MetricQ2 2024Q1 2025Q2 2025
EBITDA Margin %72.63%*24.58%*129.23%*
Net Income Margin %61.90%*14.72%*117.68%*

Values retrieved from S&P Global.*

Production and Pricing KPIs

KPIQ2 2024Q1 2025Q2 2025
Mineral & Royalty Production (MBoe/d)38.2 34.2 33.2
Working Interest Production (MBoe/d)2.2 1.3 1.4
Total Production (MBoe/d)40.4 35.5 34.6
Natural Gas Mix (%)73% 78% 72%
Realized Oil Price ($/Bbl)$77.53 $69.96 $64.67
Realized Gas Price ($/Mcf)$2.23 $3.92 $3.37
Realized Price ($/Boe)$30.01 $33.94 $32.40
Lease Bonus & Other ($USD Millions)$4.8 $6.9 $4.7
Derivative Gain/(Loss) ($USD Millions)$(5.5) $(56.0) $52.8
Distribution per Unit ($)$0.375 (Q4 ref) $0.375 $0.30
Coverage (x)~1.03x (Q4 ref) ~0.93x ~1.18x
Debt ($USD Millions)$25.0 (Q4 end) $63.0 (Q1 end) $99.0 (Q2 end), $71.0 (Aug 1)

Revenue Breakdown

Revenue Component ($USD Millions)Q2 2024Q1 2025Q2 2025
Oil & Condensate Sales$73.9 $50.1 $55.8
Natural Gas & NGL Sales$36.5 $58.2 $46.2
Lease Bonus & Other$4.8 $6.9 $4.7
Revenue from Contracts$115.2 $115.3 $106.7

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Total Production (MBoe/d)FY 202538–41 33–35 Lowered
Percentage Royalty Interest (%)FY 202596% Not updated in Q2 releaseN/A
Natural Gas Mix (%)FY 202577% Not updated in Q2 releaseN/A
Distribution per Unit ($)Q2 2025$0.375 (Q1 actual) $0.30 Lowered
2026 Production Outlook (incremental over 2025)FY 2026N/A+3–5 MBoe/d (management outlook) New directional outlook

Note: No explicit revenue, margin, OpEx, OI&E, tax rate guidance updates were provided in Q2 beyond production; hedging tables were updated for oil/gas swaps through 2026 .

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2024, Q1 2025)Current Period (Q2 2025)Trend
Natural Gas Outlook & LNG DemandConstructive LNG-led gas outlook; positioning for 2025 growth Outlook remains robust; delayed activity in 2025 but plan to ramp in 2026 Positive long-term; near-term slower
Shelby Trough DevelopmentAethon 3 rigs; ADAs in LA Haynesville; targeted acquisitions to expand footprint Revenant agreement (~270k acres; 6 wells in 2026 ramping to 25/yr); marketing additional ~180k acres; obligations more than doubling Acceleration and operator diversification
Permian Liquids ContributionLarge Culberson program (37 wells planned) with 2025 TTS expected “Cotera” project remains on track; 22 wells expected TTS in H2’25; supports oil mix recovery into 2026 Ramping liquids volumes
Distributions & CoverageMaintained $0.375 with ~1.03x (Q4) and 0.93x (Q1) coverage Reduced to $0.30; coverage improved to ~1.18x; disciplined capital deployment Near-term cut, stronger coverage
Operator Cadence & AgreementsAethon TTS cadence; ADAs add near-term certainty Rebalanced Aethon wells (mid-20s to high-teens/yr) offset by adding operators; ramp needs time (infra, spool-up) Multi-operator ramp over multi-years
Acquisitions~$130M minerals since Sep’23 $31.2M acquired in Q2; cumulative $172.3M through July’25, focused on Shelby Trough Ongoing targeted build-out

Management Commentary

  • “We see contractual development obligations more than doubling over the next five years… provide confidence in significant long-term growth.” — Thomas L. Carter, Jr. .
  • “We expect to see production growing in 2026 and distributions surpassing the previous high-water mark over the next six years.” — Thomas L. Carter, Jr. .
  • “Our new guidance reflects slower than expected natural gas production growth… particularly in the Shelby Trough and Haynesville/Bossier.” — Taylor DeWalch .
  • On Western Haynesville/Shelby Trough geology: “Formations are getting thicker and deeper… increasing productivity and EURs… operational efficiencies can tie to further development” — Taylor DeWalch .
  • On operator mix: “We restructured our agreement with Aethon… and are adding operators… staggering wells in ’28–’30; takes time to spool up.” — Thomas L. Carter .

Q&A Highlights

  • Activity ramp timing: Management expects Revenant’s initial wells in 2026 with obligations increasing to 25/yr; time needed for multi-operator spool-up and infrastructure alignment, explaining the 2025 guide reset .
  • Production mix outlook: Oil contribution should improve with Permian volumes; 2026 mix likely closer to 25–26% oil vs Q1 2025, aiding cash flows .
  • Development cadence: Aethon wells per year rebalanced lower, offset by Revenant and a new operator on marketed acreage; cumulative required wells targeted “well north” of prior single-operator cadence .
  • Shelby Trough geology: Increasing thickness/depth and analogous characteristics to Western Haynesville support longer-run development potential .

Estimates Context

MetricQ2 2024Q1 2025Q2 2025
Revenue Consensus Mean ($USD)124,236,500*115,754,000*112,646,500*
Revenue Actual ($USD)110,382,000*108,328,000*101,996,000*
Surprise (%)−11.2%*−6.4%*−9.4%*
Primary EPS Consensus Mean ($)0.3700*0.3300*0.3250*
Primary EPS Actual ($)0.3732*0.2902*0.2794*
Surprise (%)+0.9%*−12.1%*−14.0%*

Values retrieved from S&P Global.*

  • Q2 2025: Revenue and EPS both missed consensus; the miss reflects lower production volumes and delayed gas-weighted activity despite supportive prices; Adjusted EBITDA was stable sequentially (company-defined) .
  • Note: S&P “Primary EPS” may differ from BSM’s per-common-unit EPS due to partnership accounting and non-GAAP vs GAAP treatments; use company EPS for distributions and SPGI EPS for estimate comparisons .

Key Takeaways for Investors

  • Near-term caution: Lowered 2025 production guidance (33–35 MBoe/d) and a 20% distribution cut reflect delayed gas activity; hedge gains buffered GAAP but do not recur predictably .
  • Structural growth setup: Revenant and marketed acreage should more than double development obligations, adding multiple operators and ramping toward late-decade activity density; expect 2026 production growth (+3–5 MBoe/d over 2025) .
  • Liquids tailwind: Permian “Cotera” program with 22 wells expected TTS in H2’25 supports improving oil mix into 2026 and distribution recovery potential .
  • Balance sheet flexibility: Debt reduced to $71.0M by Aug 1 with cash ~$7.9M; reaffirmed $580M borrowing base and $375M commitments provide optionality for targeted acquisitions .
  • Estimate resets likely: Consensus should move lower on 2025 volumes; watch Investor Day for updated cadence, operator mix, and 2026 trajectory. Near-term trading may hinge on updated guidance/coverage vs LNG-led gas sentiment .
  • Hedge posture: Updated oil/gas swaps through 2026 provide visibility on a portion of cash flows; recognize differences between GAAP derivative marks and cash settlements when modeling distributable cash flow .
  • Monitoring items: Aethon cadence, Revenant initial spuds, additional operator placement on ~180k acres, ADA well TTS pace in Louisiana, and Permian TTS timing into Q4’25 .
Notes:
- Document citations embedded per table and sections.
- S&P Global consensus/actual values marked with * and may reflect different metric definitions than company-reported per-common-unit EPS and Adjusted EBITDA.