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Energy Transfer LP (ET)·Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 delivered mixed results: revenue of $19.24B and EPS of $0.32, with Adjusted EBITDA up year over year to $3.87B and DCF (as adjusted) at $1.96B, while net income fell YoY due to lower crude marketing and Bakken volumes .
  • Versus S&P Global consensus, ET missed on revenue and EPS; EBITDA (SPGI definition) also came in below consensus. Management lowered 2025 Adjusted EBITDA outlook to “at or slightly below” the lower end of the prior $16.1–$16.5B range, citing Bakken weakness, slower dry gas recovery, and reduced gas optimization volatility .
  • Strategic catalysts: FID on the 1.5 Bcf/d Desert Southwest pipeline ($5.3B, in-service 4Q 2029) and continued progress on Lake Charles LNG commercialization; three signed Texas data center gas deals and rapid Permian processing ramp underpin medium-term growth .
  • Distribution raised to $0.33 per unit for Q2 (annualized $1.32), up >3% YoY, reinforcing capital return amid elevated capex .

What Went Well and What Went Wrong

What Went Well

  • Segment strength despite macro headwinds: Adjusted EBITDA rose YoY to $3.87B on Interstate (+$78M YoY), Midstream (+$75M), and Sunoco LP (+$134M), with multiple throughput records across midstream, crude, NGL transportation, terminals, exports, and fractionation .
  • Strategic project momentum: Announced the 516-mile, 42-inch Desert Southwest expansion (1.5 Bcf/d design, backed by IG commitments), with potential expansion to larger diameter; management targets mid-teens returns (“six times is a pretty good number”) .
  • Data center gas demand building: “We’ve signed three deals now in Texas,” including a behind-the-meter hyperscaler contract ramping from ~80,000 to ~380,000 MMBtu/d, with flexibility to ~475,000; cadence of further announcements expected .

What Went Wrong

  • Guidance trimmed: 2025 Adjusted EBITDA now “at or slightly below” the low end of the $16.1–$16.5B range due to Bakken weakness, slower dry gas recovery, and low volatility in gas optimization .
  • Crude segment pressure: Q2 crude Adjusted EBITDA fell YoY ($732M vs $801M) on lower Bakken transportation revenues and higher expenses (ET-S Permian JV costs, employee, projects) .
  • Intrastate margin compression: Q2 intrastate Adjusted EBITDA declined YoY ($284M vs $328M) as pipeline optimization volumes shifted to long-term third-party contracts and price spreads narrowed .

Financial Results

Headline Financials vs Prior Periods

MetricQ2 2024Q1 2025Q2 2025
Revenue ($USD Billions)$20.73 $21.02 $19.24
Net Income Attributable to Partners ($USD Billions)$1.31 $1.32 $1.16
EPS (Basic, $)$0.35 $0.37 $0.32
Adjusted EBITDA ($USD Billions)$3.76 $4.10 $3.87
DCF to Partners, as adjusted ($USD Billions)$2.04 $2.31 $1.96
Growth Capex ($USD Billions)N/A$0.96 $1.04
Maintenance Capex ($USD Billions)N/A$0.17 $0.25

Results vs S&P Global Consensus (Q2 2025)

MetricActualConsensusBeat/Miss
Revenue ($USD Billions)$19.24 $22.53*Miss*
EPS ($)$0.32 $0.326*Miss*
EBITDA (SPGI definition, $USD Billions)$3.70*$3.92*Miss*

Values retrieved from S&P Global.*

Note: Company-reported Adjusted EBITDA was $3.87B ; SPGI “EBITDA” measures may differ from company non-GAAP definitions.

Segment Adjusted EBITDA (Q2 2025 vs Q2 2024)

SegmentQ2 2024 ($MM)Q2 2025 ($MM)
Intrastate Transportation & Storage$328 $284
Interstate Transportation & Storage$392 $470
Midstream$693 $768
NGL & Refined Products$1,070 $1,033
Crude Oil Transportation & Services$801 $732
Investment in Sunoco LP$320 $454
Investment in USAC$144 $149
All Other$12 $(24)
Total Adjusted EBITDA (Consolidated)$3,760 $3,866

KPIs and Operating Metrics

KPIQ2 2024Q2 2025
Interstate NG Transport (BBtu/d)16,337 18,153
Intrastate NG Transport (BBtu/d)13,143 14,229
Midstream Gathered Volumes (BBtu/d)19,437 21,329
NGL Transport (MBbl/d)2,235 2,331
NGL Fractionation (MBbl/d)1,093 1,150
Crude Transport (MBbl/d)6,490 7,049
NGL & Refined Products Terminal (MBbl/d)1,506 1,553
Distribution per Unit ($)$0.32 (approx., reference)$0.33
Revolver Availability ($MM)N/A$2,506

Margins (S&P Global)

MetricQ3 2024Q1 2025Q2 2025
EBITDA Margin (%)16.87*N/A19.21*
Net Income Margin (%)5.69*N/A6.04*

Values retrieved from S&P Global.*

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Adjusted EBITDAFY 2025$16.1B–$16.5B “At or slightly below” low end of $16.1B–$16.5B Lowered
Growth CapexFY 2025~$5.0B ~$5.0B Maintained
Quarterly DistributionQ2 2025$0.3275 (Q1 2025) $0.33 Raised

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2024, Q1 2025)Current Period (Q2 2025)Trend
AI/Data Center Gas DemandExecuted deal with CloudBurst: up to 450,000 MMBtu/d; behind/at-the-meter mix evolving Three Texas deals signed; hyperscaler contract ramped to ~380,000 MMBtu/d with flex to ~475,000; more announcements expected Accelerating
Desert Southwest PipelineNot yet announcedFID on 516-mile, 42-inch, 1.5 Bcf/d; mid-teens returns; potential upsizing to 48-inch New growth vector
Permian ProcessingUpgrades and Mustang Draw plant planned; record throughput targets Lenorah II (200 MMcf/d) and Badger (200 MMcf/d) in service; Mustang Draw expected 2026 Capacity ramp
Lake Charles LNGHOA with MidOcean (30% equity/production), SPAs with Chevron/Japanese utility; targeting FID by year-end EPC quotes in line; continued SPA/HOA progress; equity sell-down prep; aiming for FID “next couple of months” process steps Advancing commercialization
Ethane/LPG Export TariffsStrong demand; ability to contract term capacity; resiliency at Nederland/Marcus Hook “No impact” on quarterly results; China tariff episode slowed contracting with Chinese crackers, focusing on other markets Manageable headwind
BakkenQ4/Q1 pressure from lower volumes and re-contracted rates Short-term volume decline due to weather, fires, curtailments; management “bullish” medium-term as temporary diversions reverse Near-term soft; medium-term constructive
Regulatory/MacroNew administration seen as supportive; permitting and LNG pause lifted; DOE/FERC support expected Continued positive permitting backdrop and engagement across agencies Supportive

Management Commentary

  • “We continue to expect to spend approximately $5,000,000,000 on organic growth capital projects in 2025… majority of earnings growth to come in 2026 and 2027.”
  • “We now expect to be at or slightly below the lower end of our guidance range of $16,100,000,000 and $16,500,000,000… result of weakness in the Bakken, slower recovery in dry gas areas, and a lack of normal volatility in our gas optimization business.”
  • On Desert Southwest: “We haven’t fully sold that out… we kicked off an evaluation today to increase that to a 48 inches… six times is a pretty good number to look at.”
  • Tone on the franchise: “Even with this challenged quarter… I’ve never been… more excited about where we sit and where the future is for our industry… and our partnership.”

Q&A Highlights

  • Data center commercialization: Multiple signed deals; contracts tailored by site with scalable volumes; ET’s big-inch pipes, storage, and proximity to transmission/fiber give edge .
  • Desert Southwest returns/capacity: Mid-teens returns; confidence in full subscription; potential diameter upsizing; traditional cost risk is borne by ET with contingencies for tariffs and permitting .
  • Lake Charles LNG: EPC pricing tracking expectations; continued SPA/HOA progress and equity partner discussions; aiming to kick off financing once target commitments are in place .
  • Bakken trajectory: Near-term headwinds (weather, fires, temporary diversions) expected to reverse; management remains “bullish” as Canadian pipeline capacity refills and volumes revert .
  • NGL capacity/use: Flexport ramp through 2025; >90% contracted from Jan 2026 under 3–5 year fixed-fee agreements .

Estimates Context

  • Q2 2025 vs S&P Global consensus: revenue $19.24B vs $22.53B*, EPS $0.32 vs $0.326*, EBITDA (SPGI) $3.70B* vs $3.92B*. Company-reported Adjusted EBITDA was $3.87B (non-GAAP) .
  • Forward consensus (illustrative): Q3 2025 EPS $0.331*, revenue $21.81B*, EBITDA $3.97B*; Q4 2025 EPS $0.367*, revenue $26.64B*, EBITDA $4.19B*. Values retrieved from S&P Global.*

Values retrieved from S&P Global.*

Implication: Near-term estimate revisions likely modestly lower for EBITDA given guidance shift to the low end; crude/Bakken and dry gas trends could temper multi-segment expectations, while Desert Southwest/Lake Charles/data center updates provide medium-term offset .

Key Takeaways for Investors

  • Near-term prints are mixed with consensus misses and a lowered 2025 Adjusted EBITDA guide; expect cautious estimate revisions and focus on Bakken/dry gas recovery cadence .
  • Strategic growth visibility is improving: Desert Southwest FID, Permian processing ramps, Flexport exports, and data center gas deals support multi-segment earnings expansion into 2026–2027 .
  • LNG optionality: Lake Charles commercialization steps (SPAs/HOAs, EPC, equity sell-down) could unlock upstream pipeline expansions and incremental returns once FID is achieved .
  • Capital returns intact: Q2 distribution lifted to $0.33; management reiterates 3–5% long-term distribution growth objective aligned with DCF per unit baseline growth .
  • Trading lens: Watch for updates on data center contracts and Desert Southwest open season; stock narrative likely pivots between near-term operational headwinds and medium-term contracted growth pipeline .
  • Segment mix evolution: Interstate/intrastate gas likely grow as a share of EBITDA over time; NGLs supported by term contracts and fractionation expansions, crude pressured by Bakken dynamics near term .

Notes on non-GAAP: Adjusted EBITDA and Distributable Cash Flow are non-GAAP measures; definitions and reconciliation provided in the release .