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ENTERPRISE PRODUCTS PARTNERS L.P. (EPD)·Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 was resilient operationally with record volumes in gas processing, gas pipeline throughput, and crude oil pipelines; non-GAAP DCF rose 7% to $1.94B and covered the raised $0.545 distribution 1.6x, retaining $748M for growth .
  • Headwinds: sharp commodity price declines and margin compression in LPG export fees and octane enhancement reduced reported revenues to $11.36B and pressured petchem margins; EPS per unit was $0.66 vs $0.64 YoY .
  • Consensus comparison: Revenue missed Wall Street ($14.18B est vs $11.36B actual) while Primary EPS was roughly in line and EBITDA slightly below; underlying fee-based assets and natural gas marketing offset crude marketing weakness (see Estimates Context) (*Values retrieved from S&P Global).
  • Execution catalyst: ~$6B of organic projects entering service in 2H25 (new Permian plants, Frac 14, BYO/Bahia, and Neches River Terminal Phase 1) with quick ramps expected, supporting volume-driven cash flow growth into 2026 .
  • Regulatory watch: BIS ethane export licensing to China caused short-term dislocations and elevated customer risk perceptions; management navigated near-term impacts but flagged strategic export risks as an ongoing theme .

What Went Well and What Went Wrong

What Went Well

  • Record throughput across the system: record natural gas processing inlet (7.8 Bcf/d), natural gas pipelines (20.4 TBtus/d), crude oil pipelines (2.6 MBD), and refined/petchem pipelines (1.0 MBD) underpinning stable cash generation .
  • Fee-based strength and gas marketing offset: “The performance of our fee-based assets and natural gas marketing more than offset lower earnings in our crude oil marketing businesses…” (Jim Teague) .
  • Capex cadence and project ramp: Two new 300 MMcf/d Permian plants commissioned with rapid ramp; NRT Phase 1 began service mid-July enabling ethane loading at 120 MBPD; Frac 14 and Bahia pipeline slated for 4Q . Management expects “Frac 14 will come up completely full,” with Bahia ~50–60% in first 12 months (ramp detail from Q&A) .

What Went Wrong

  • LPG export fee compression: Gross margin at EHT’s LPG-related activities fell 46% ($37M) on recontracting to current market and ~60% drop in spot rates, despite higher export volumes; spot fee declines were called out on the call .
  • Octane enhancement margins normalized: Segment gross margin fell $49M on lower sales margins; management cited new supply and China-driven pressure on MTBE markets as structural headwinds .
  • Crude oil marketing softness: Net $14M decline in crude assets/marketing on lower sales volumes; crude marine volumes dropped vs prior year (811 MBPD vs 977 MBPD) .

Financial Results

Consolidated P&L, Cash Flow and Key Non-GAAP

MetricQ2 2024Q1 2025Q2 2025
Revenue ($USD Billions)$13.48 $15.42 $11.36
Net Income Attributable to Common Unitholders ($USD Billions)$1.41 $1.39 $1.44
EPS per Common Unit (Fully Diluted, $)$0.64 $0.64 $0.66
Operating Income ($USD Billions)$1.77 $1.76 $1.80
Adjusted EBITDA ($USD Billions)$2.39 $2.44 $2.41
Distributable Cash Flow (DCF) ($USD Billions)$1.81 $2.01 $1.94
Adjusted CFFO ($USD Billions)$2.07 $2.11 $2.11
Net Cash Flow from Operating Activities ($USD Billions)$1.57 $2.31 $2.06
Distribution per Unit ($)$0.525 (implied) $0.535 $0.545

Notes:

  • Non-GAAP definitions and reconciliations provided in press release exhibits .
  • DCF coverage of Q2 distribution = 1.6x; $748M retained .

Segment Gross Operating Margin

Segment GOM ($USD Millions)Q2 2024Q1 2025Q2 2025
NGL Pipelines & Services$1,325 $1,418 $1,297
Crude Oil Pipelines & Services$417 $374 $403
Natural Gas Pipelines & Services$293 $357 $417
Petrochemical & Refined Products Services$392 $315 $354
Total Segment GOM$2,427 $2,464 $2,471
Non-GAAP Total GOM$2,412 $2,431 $2,477

Operating KPIs

KPIQ2 2024Q1 2025Q2 2025
Natural Gas Pipeline Volumes (TBtus/d)18.7 20.3 20.4
NGL Pipeline Transportation (MBPD)4,341 4,447 4,562
NGL Marine Terminal (MBPD)876 994 942
NGL Fractionation (MBPD)1,679 1,652 1,667
Crude Oil Pipeline (MBPD)2,528 2,484 2,622
Crude Oil Marine (MBPD)977 736 811
Propylene Production (MBPD)107 113 118
Natural Gas Processing Inlet (MMcf/d)7,513 7,719 7,768
Fee-based Gas Processing (MMcf/d)6,578 7,181 7,266
Equivalent Pipeline Volumes (MBPD)12,754 13,225 13,562

Margin Metrics (S&P Global)

MetricQ2 2024Q1 2025Q2 2025
EBITDA ($USD Billions)$2.279*$2.313*$2.357*
EBITDA Margin (%)16.90%*15.00%*20.74%*
EBIT ($USD Billions)$1.668*$1.677*$1.714*
EBIT Margin (%)12.37%*10.88%*15.08%*
Net Income Margin (%)10.41%*9.04%*12.62%*

Values marked with * retrieved from S&P Global.

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Organic Growth CapexFY 2025$4.0–$4.5B $4.0–$4.5B Maintained
Organic Growth CapexFY 2026$2.0–$2.5B $2.0–$2.5B Maintained
Sustaining CapexFY 2025~$525M ~$525M Maintained
Quarterly DistributionQ2 2025$0.535 (Q1 level) $0.545 Raised
Project Commissioning2H 2025Major projects entering service ~$6B projects in 2H25 (Permian plants, Frac 14, BYO/Bahia, NRT Phase 1) Timing affirmed

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2024)Previous Mentions (Q1 2025)Current Period (Q2 2025)Trend
Permian-driven volume growthRecord volumes; capacity expansions under construction Two Permian plants slated for 3Q; Leonidas/Mentone 3 ramp Two new plants commissioned; rapid ramp to full; continued gassier basin outlook Strengthening volumes
LPG export fees/competitionSolid 4Q margins; capacity additions pipeline Not prominent; ethane export terminal gains Margin compression via recontracting & 60% spot fee drop; 85–90% contracted through decade Pressure rising
Octane enhancementPrior strength normalizing Sharp margin declines and lower deficiency revenues Margins normalized; China supply pressure persists Normalized/lower
Ethane export regulatory risk (BIS)N/AN/ABIS ethane licensing to China disrupted cargoes; brand/reliability concerns noted Emerging regulatory risk
Capital returns (buybacks)$63M 4Q buybacks; disciplined returns $60M buybacks; 60% of $2B program utilized $110M buybacks; opportunistic; larger in 2026 as FCF steps up Increasing flexibility
Acadian/Haynesville leverageN/AN/ARecontracting at 2–3x historical rates amid LNG-linked activity Improving rates

Management Commentary

  • “In a seasonally weaker quarter challenged with macroeconomic, geopolitical, and commodity price headwinds, Enterprise reported solid earnings and cash flow… setting five new operating records” — Jim Teague .
  • “The performance of our fee-based assets and natural gas marketing more than offset lower earnings in our crude oil marketing businesses…” — Jim Teague .
  • “We are excited for the opportunities the second half of 2025 is poised to present with approximately $6 billion of our organic growth capital projects slated to enter commercial service.” — Jim Teague .
  • “LPG export volumes rose… yet our gross operating margin declined by $37 million… driven by recontracting and a 60% drop in spot rates.” — Jim Teague (call) .
  • “Acadian recontracting rates… two to three times historical… we will reap benefits.” — Natalie Gayden .

Q&A Highlights

  • Project ramps: Frac 14 “completely full,” Bahia ~50–60% in first year; NRT ramp tied to VLEC orders; Permian plants ramp quickly (implying strong early contribution in 4Q/1Q) .
  • LPG exports: 85–90% contracted through decade; margin headwinds mostly recognized; volume growth to offset lower fees .
  • Permian outlook: Basin getting “gassier,” but producers remain profitable; management expects E&Ps to hold guidance; supportive for EPD’s gas/NGL value chain .
  • Ethane export licensing (BIS): Near-term impact managed; raised concerns about U.S. brand reliability; potential customer preference shifts noted .
  • Capital allocation: Opportunistic buybacks in 2025; larger opportunity in 2026 as discretionary FCF steps up; ~$2.2B of 2026 capex committed .

Estimates Context

Metric (SPGI Consensus)Q2 2024Q1 2025Q2 2025
Primary EPS Consensus Mean ($)0.671*0.702*0.635*
Primary EPS Actual ($)0.642*0.658*0.634*
Revenue Consensus Mean ($USD Billions)$14.27*$14.00*$14.18*
Revenue Actual ($USD Billions)$13.48*$15.42*$11.36*
EBITDA Consensus Mean ($USD Billions)$2.417*$2.548*$2.437*
EBITDA Actual ($USD Billions)$2.279*$2.313*$2.357*

Values marked with * retrieved from S&P Global.

Implications:

  • Revenue: Q2 2025 was a significant miss versus consensus (driven by lower commodity prices and recontracting/spot fee compression in LPG and weaker crude marketing) .
  • EPS: Primary EPS roughly in line/slight miss versus consensus; GAAP EPS per unit reported at $0.66 (non-comparable to SPGI primary EPS) .
  • EBITDA: Slight miss versus consensus, cushioned by MTM gains (+$52M) and strong fee-based pipelines; natural gas marketing MTM uplift (+$55M) aided segment results .

Key Takeaways for Investors

  • Volume-driven resilience: Record throughput in gas/NGL/crude pipelines and processing supports stable DCF even in weak pricing; watch rapid ramp of 2H25 projects for 4Q/1Q run-rate uplift .
  • Margin mix shift: Expect continued pressure in LPG export fees and normalized octane margins; mix should tilt further to fee-based pipelines, fractionation, and gas marketing .
  • Regulatory risk: BIS ethane export licensing adds tail risk to ethane flows to China; EPD’s diversified customer base mitigates near-term impact, but could affect long-term contracting terms and pricing .
  • Cash return cadence: With capex stepping down in 2026 and major projects online, discretionary FCF should increase, enabling larger buybacks and sustained distribution growth .
  • Permian gas leverage: Basin getting gassier; EPD’s integrated NGL value chain and gas gathering/intrastate systems are well positioned; Acadian recontracting at 2–3x historical rates is an upside rate tailwind .
  • Near-term trading lens: Headline revenue miss may weigh, but focus on DCF coverage, retained cash, and visible project ramp; monitor 4Q commissioning milestones (Frac 14, BYO/Bahia) for volume catalysts .
  • Estimate revisions: Expect sell-side to lower revenue/petchem margin assumptions, modestly adjust EBITDA; fee-based volumes and MTM contributions provide partial offset (*Values retrieved from S&P Global) .

Appendix: Commodity Price Backdrop

  • Weighted-average indicative NGL prices at Mont Belvieu dipped to $0.58/gal in Q2 2025 vs $0.59/gal YoY; WTI averaged $63.87 in Q2 2025 vs $80.57 in Q2 2024, framing lower marketing revenues .