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MN

MACH NATURAL RESOURCES LP (MNR)·Q3 2025 Earnings Summary

Executive Summary

  • Q3 2025 delivered strong operational execution but a GAAP net loss driven by a $90.4M impairment and unique ICAV transaction expenses; Adjusted EBITDA was $124M and operating cash flow was $106M .
  • Distribution was set at $0.27/unit; management noted non-recurring ~$13M ICAV deal costs reduced the payout by ~$0.08/unit, with full-quarter contribution from acquired assets expected to lift near-term distributions .
  • 2026 outlook was updated: drilling & completion capital cut by 18% (−$63M) while maintaining prior production guidance—reflecting better capital efficiency from high-rate Deep Anadarko and Mancos gas wells .
  • Versus S&P consensus, Q3 missed on EPS and modestly on revenue and EBITDA (EPS −$0.28 vs $0.32; revenue $237.4M vs $248.2M; EBITDA $136.8M vs $138.9M)—largely due to impairment and timing of acquisitions [GetEstimates] .

What Went Well and What Went Wrong

What Went Well

  • Deep Anadarko two-well pad exceeded 40 MMcf/d combined, with PV10 around $15M per location at ~$14M cost; early results support capital efficiency gains .
  • Mancos Shale five-well program achieved >100 MMcf/d combined IP, with three-mile pad at ~70 MMcf/d and expected EURs of 24 Bcf per 3-mile lateral, underpinning the 2026 gas-weighted plan .
  • Management reduced 2026 D&C capital by 18% while maintaining production guidance: “Is that really the driver... or is there something else at work?” “Nope, that’s it.” (efficiency from gas wells) .

What Went Wrong

  • GAAP net loss of $36M in Q3 due to a $90.4M impairment; Adjusted EBITDA declined YoY (Q3’24 $132.7M vs Q3’25 $124.2M) .
  • Distribution fell to $0.27/unit; unique $13M ICAV deal costs (expensed), and only ~two weeks of acquired asset contribution depressed the payout in Q3 .
  • Basis/macro caution around near-term gas pricing; management remains bullish longer-term but flagged winter-weather uncertainty and storage/takeaway dynamics .

Financial Results

Income Statement and Cash Flow (quarterly)

MetricQ1 2025Q2 2025Q3 2025
Revenues ($USD)$254.687M*$222.442M*$237.436M*
Net Income ($USD)$15.886M*$89.661M*$(35.654)M*
EBITDA ($USD)$115.257M*$178.395M*$136.808M*
Diluted EPS ($)$0.1416*$0.7577*$(0.2819)*
EBITDA Margin (%)45.25%*80.20%*57.62%*
Net Income Margin (%)6.24%*40.31%*−15.02%*
Cash from Operations ($USD)$142.519M* $130.141M* $105.547M*
Capital Expenditure ($USD)$(80.690)M*$(134.596)M*$(596.929)M*
Cash & Equivalents ($USD)$7.790M $13.777M $53.599M

Values retrieved from S&P Global.*

YoY Snapshot

MetricQ3 2024Q3 2025
Revenues ($USD)$212.068M*$237.436M*
Net Income ($USD)$67.444M* $(35.654)M*
EBITDA ($USD)$160.311M*$136.808M*
Diluted EPS ($)$0.6963* $(0.2819)*
EBITDA Margin (%)75.59%*57.62%*
Net Income Margin (%)31.80%*−15.02%*

Values retrieved from S&P Global.*

Estimates Comparison (S&P Global)

MetricConsensus (Q3 2025)Actual (Q3 2025)
EPS ($)$0.3233*$(0.2800)*
Revenue ($USD)$248.226M*$237.436M*
EBITDA ($USD)$138.850M*$136.808M*
EPS - # of Estimates3*—
Revenue - # of Estimates5*—

Values retrieved from S&P Global.*

Commodity Mix and Pricing

MetricQ1 2025Q2 2025Q3 2025
Average Realized Oil Price ($/Bbl)$70.75 $63.10 $64.79
Average Realized Gas Price ($/Mcf)$3.56 $2.81 $2.54
Average Realized NGL Price ($/Bbl)$27.33 $22.41 $21.78
Oil/Gas/NGL Production Mix (%)24/53/23 23/53/24 21/56/23
Production Revenues Contribution (Oil/Gas/NGL %)49/33/18 51/31/18 50/32/18
Avg Net Production (Mboe/d)80.9 83.6 94.0

Operating Cost KPIs

MetricQ1 2025Q2 2025Q3 2025
LOE ($MM; $/Boe)$49; $6.69 $50; $6.52 $59; $6.82
Gathering & Processing ($MM; $/Boe)$28; $3.87 $32; $4.18 $33; $3.83
Production Taxes (% of sales)~5.1% ~4.8% ~4.4%
Midstream Operating Profit ($MM)~$4 ~$4 ~$3
G&A ex SBC ($MM)$9 $7 $21 (ex SBC); ICAV deal costs ~$13 counted in G&A
Interest Expense ($MM)$18 $12 $17
Development Costs ($MM)$52 $64 $59

Note: The CFO cited Q3 LOE as $50MM/$6.52 per Boe (likely classification differences); the press release reported $59MM/$6.82 per Boe .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
D&C Capital ($)FY 2026Prior plan (not quantified)−18% (−$63M) vs priorRaised efficiency (lowered capital)
Production GuidanceFY 2026Prior expectationsMaintainedMaintained
Gas Mix (%)FY 2026~two-thirds discussed“Just over 70%” gasRaised gas skew
Midstream & Land Budget ($)FY 2026Prior updateLand ~$32M; Midstream ~$17MIncreased maintenance/upgrade focus
Distribution DirectionNear-termN/AExpect higher with full-quarter contribution, absent expensed deal costsConstructive
Quarterly DistributionQ3 2025N/A$0.27/unitDeclared

Earnings Call Themes & Trends

TopicPrevious Mentions (Q1 & Q2 2025)Current Period (Q3 2025)Trend
Reinvestment rate discipline (<50%)Reaffirmed, 37% in Q1; ~50% for FY plan Maintained; capital flexed to gas opportunities Consistent discipline
Gas-weighted pivot (Deep Anadarko, Mancos)Planned 2026 gas growth >70% mix; adding rigs Execution underway; >40 MMcf/d Anadarko pad; >100 MMcf/d Mancos five wells Accelerating
Capital efficiency/cost reductionOswego cost excellence; target $14M Anadarko wells Targeting $12–15M/well; cutting stimulation costs to boost IRR Improving
Hedging posture12‑mo hedge avg $69 oil/$3.77 gas ~60% hedged on 2026 gas when including San Juan hedges Increased gas hedge
Leverage & liquidityNet debt/EBITDA ~0.7x Q1; RBL upsizing Pro forma ~1.3x post acquisitions; $54M cash, $295M availability Higher, manageable
M&A & equity-funded dealsPursuing accretive PDP at discount; XTO $60M ICAV/Savinol closed; bolt-ons targeted ($100–$150M) Ongoing, disciplined
Marketing/basis managementChanged gas marketing arrangements; NextEra Macro/basis caution persists into winter Neutral to cautious

Management Commentary

  • “These transactions have transformed our scale and operating footprint... we are focused on integrating these assets and deploying capital efficiently... delivering cash to our unitholders.” — Tom L. Ward, CEO .
  • “We show an example of that capital efficiency by lowering our expected CapEx 8% for 2026 without affecting our production guidance.” — Tom L. Ward (prepared remarks) .
  • “Excluding [~$13M] deal costs, recurring cash G&A was around $7.2M or $0.83 per BOE... distributions before the G&A impact would have been approximately $0.35 per unit.” — Kevin White, CFO .
  • “In the Deep Anadarko... producing more than 40 MMcf/d... anticipate more than 20 Bcf per three-mile lateral with a PV10 of approximately $15M per location.” — Tom L. Ward .
  • “Our three-well, three-mile [Mancos] pad... producing more than 70 MMcf/d... EUR of 24 Bcf and PV10 around $14M.” — Tom L. Ward .

Q&A Highlights

  • Distribution trajectory: Management expects higher payouts in upcoming quarters as acquisitions contribute a full quarter and absent expensed deal costs .
  • Gas strategy and takeaway: Midcon and San Juan positioned with ample takeaway; 2026 program targets dry gas with multiple Anadarko/Mancos pads .
  • 2026 guidance changes: Capital reduction driven by stronger gas well performance and lower strip; production guidance maintained .
  • Potential drilling partner: Considering a partner to accelerate development across vast deep-gas inventory without exceeding reinvestment discipline .
  • Hedging: 2026 gas ~60% hedged; bullish on 2027 demand as LNG ramps, near-term caution on winter basis/storage .

Estimates Context

  • Q3 2025 vs consensus: EPS −$0.28 vs $0.32; Revenue $237.4M vs $248.2M; EBITDA $136.8M vs $138.9M (misses driven by impairment and transaction costs, with only ~two weeks of acquired asset contribution in Q3)* [GetEstimates]* .
  • Forward implications: With full-quarter contributions from ICAV/Savinol in Q4 and capital efficiency gains in Anadarko/Mancos, Street models may need to raise forward revenue/distribution trajectories, while normalizing for non-recurring G&A and impairment effects .

Values retrieved from S&P Global.*

Key Takeaways for Investors

  • Q3’s GAAP loss was non-recurring in nature (impairment, deal costs), while cash-generation remained intact (OCF $106M; Adjusted EBITDA $124M) .
  • Distribution reset to $0.27 reflects timing and accounting; management signaled higher near-term payouts as acquisitions contribute fully and deal costs roll off .
  • Capital efficiency momentum: 2026 D&C cut 18% with unchanged production guidance—anchored by strong early Anadarko/Mancos results .
  • Gas-levered 2026-2027: Portfolio skew >70% gas in 2026; robust hedge coverage and constructive LNG-driven demand support medium-term cash flows .
  • Operational cadence flexibility enables monthly pivoting of rigs/capital to maximize IRR under reinvestment discipline (<50% of OCF) .
  • Watch basis/takeaway and winter pricing; near-term macro can pressure realizations but company positioning and hedges mitigate risk .
  • Tactical M&A: Bolt-ons in $100–$150M range and equity-funded structures remain core to accretive CAD growth and diversification .