Executive Summary

Mixed quarter: Q3 revenue of $19.95B and basic EPS of $0.28 missed S&P Global consensus ($21.81B revenue, $0.33 EPS), with EBITDA also below consensus; management cited several one-time items and segment-specific headwinds as contributors . Revenue/EPS consensus from S&P Global estimates: $21.81B*, $0.331*, EBITDA $3.97B* (company-reported Adjusted EBITDA was $3.84B) .
Guidance trimmed: 2025 Adjusted EBITDA now expected to be slightly below the low end of $16.1–$16.5B (lowered from prior stance) and 2025 growth capex reduced to ~$4.6B (from ~$5.0B); 2026 growth capex guided to ~$5B .
Structural demand tailwinds: data-center and power demand accelerating—ET disclosed multiple long-term Oracle contracts (~900 MMcf/d), >6 Bcf/d of new demand-pull contracts with ~18-year average lives and >$25B of expected firm-transport revenue, and fully contracted 1.5 Bcf/d Desert Southwest pipeline with potential upsizing .
Strategic optionality: considering converting one Permian NGL pipeline to natural gas service given tighter NGL transport economics vs superior gas transport returns; DAPL/ETCOP initiatives with Enbridge to bring Canadian heavy barrels bolster crude utilization into the 2030s .
Distribution raised to $0.3325 per unit (annualized $1.33), up >3% YoY; liquidity strong with $3.44B revolver availability at 9/30/25 .

What Went Well and What Went Wrong

What Went Well
- Record volumes across multiple assets: NGL transportation (+11%), NGL exports (+13%), NGL/refined products terminal volumes (+10%), midstream gathered volumes (+3%) YoY; strong interstate (+8%) and intrastate (+5%) gas transport .
- Commercial momentum: fully contracted 1.5 Bcf/d Desert Southwest project (25-year terms), Oracle multi-site gas supply (~900 MMcf/d), >6 Bcf/d of new demand-pull capacity signed with >$25B revenue over ~18 years . “These contracts have a weighted average life of over 18 years and are expected to generate more than $25 billion of revenue from firm transportation fees” .
- NGL segment growth: Adj. EBITDA up YoY on higher throughput and terminal fees; LPG export capacity at Nederland ~95% contracted through decade-end; Flexport ramping and ethylene export-ready .
What Went Wrong
- Headline misses vs estimates: revenue $19.95B vs $21.81B*, EPS $0.28 vs $0.33*, EBITDA (S&P definition) $3.59B vs $3.97B*; management cited several one-time items, including Rover ad valorem tax accrual ($43M) and NGL remediation costs ($17M) .
- Intrastate EBITDA down on lower optimization as business shifts to long-term third‑party contracts; Midstream YoY comp impacted by $70M prior-year business interruption proceeds; Crude pressured by lower Bakken/Bayou Bridge revenue and higher OpEx .
- Guidance tightened: 2025 Adjusted EBITDA now “slightly below” the low end of $16.1–$16.5B range; 2025 growth capex reduced to ~$4.6B (timing deferrals) .

Financial Results

Quarterly trend (Q1–Q3 2025):

Metric	Q1 2025	Q2 2025	Q3 2025
Revenue ($B)	$21.02	$19.24	$19.95
Basic EPS ($)	$0.37	$0.32	$0.28
Adjusted EBITDA ($B)	$4.10	$3.87	$3.84
DCF to Partners (Adj., $B)	$2.31	$1.96	$1.90

Q3 2025 vs prior year and vs estimates:

Metric	Q3 2024	Q3 2025 Actual	S&P Global Consensus	Result
Revenue ($B)	$20.77	$19.95	$21.81*	Miss*
Basic EPS ($)	$0.33	$0.28	$0.331*	Miss*
EBITDA ($B, S&P definition)	—	$3.59*	$3.97*	Miss*
Adjusted EBITDA ($B, company)	$3.96	$3.84	—	Down YoY

Notes: EBITDA consensus/actual are S&P Global’s EBITDA metric; company emphasizes Adjusted EBITDA (non‑GAAP) at $3.84B . Values marked with * retrieved from S&P Global.

Segment Adjusted EBITDA ($MM):

Segment	Q1 2025	Q2 2025	Q3 2025
Intrastate transport & storage	$344	$284	$230
Interstate transport & storage	$512	$470	$431
Midstream	$925	$768	$751
NGL & refined products	$978	$1,033	$1,054
Crude oil	$742	$732	$746
Investment in Sunoco LP	$458	$454	$489
Investment in USAC	$150	$149	$160
All other	$(11)	$(24)	$(23)
Adjusted EBITDA (consol.)	$4,098	$3,866	$3,838

Operating KPIs (selected):

KPI	Q1 2025	Q2 2025	Q3 2025
NGL transport (MBbls/d)	2,169	2,331	2,487
NGL & refined products terminal (MBbls/d)	1,453	1,553	1,660
NGL fractionation (MBbls/d)	1,089	1,150	1,123
Interstate gas transported (BBtu/d)	18,204	18,153	18,013
Intrastate gas transported (BBtu/d)	14,220	14,229	13,861
Midstream gathered (BBtu/d)	20,411	21,329	21,581
Crude oil transport (MBbls/d)	6,719	7,049	7,023

Drivers and one-time items:

Interstate: $43M accrual for prior-period ad valorem tax on Rover; otherwise underlying demand was higher YoY .
NGL & refined products: +$92M transportation margin and +$11M terminals margin, offset by +$51M OpEx including $17M one-time investigation/remediation costs, lower fractionation throughput due to maintenance .
Midstream: YoY comp includes $70M business interruption proceeds recognized in 3Q24; current quarter saw higher Permian volumes but higher OpEx and lapped one-time benefit .
Crude: lower Bakken/Bayou Bridge revenue and higher OpEx, partially offset by Texas system growth .

Guidance Changes

Metric	Period	Previous Guidance	Current Guidance	Change
Adjusted EBITDA	FY 2025	$16.1–$16.5B	Slightly below low end (~<$16.1B)	Lowered
Growth Capex	FY 2025	~$5.0B	~$4.6B	Lowered
Growth Capex	FY 2026	—	~$5.0B	New
Distribution per unit	Q3 2025	$0.33 for Q2 2025	$0.3325 (annualized $1.33)	Increased

Management also reiterated strong long-term, contracted backlog (Hugh Brinson, Desert Southwest, Bethel storage) and high demand-pull exposure supporting multiyear growth .

Earnings Call Themes & Trends

Topic	Previous Mentions (Q1 & Q2 2025)	Current Period (Q3 2025)	Trend
Data centers & power demand	Q1: long-term agreement with CloudBurst; Q2: Desert Southwest announced; demand-pull emerging	Oracle multi-site gas supply (~900 MMcf/d); >6 Bcf/d of demand-pull signed, >$25B revenue, ~18-year life; “bring-your-own-electricity” dynamics favorable to gas	Rapidly strengthening; larger, longer, more contracted
Hugh Brinson pipeline	Q1: construction commenced; steel secured	Phase 1 ROW 100% acquired; construction on all spreads; bi-directional 2.2 Bcf/d west→east, ~1 Bcf/d east→west; first flow late 2026; options for customer upsizing	Executing to plan; demand-pull increasing
Desert Southwest (Transwestern)	Q2: 1.5 Bcf/d expansion announced (~$5.3B, in-service 4Q29)	Fully contracted 25-year terms; strong interest to upsize; pipe size decision window open; potential +0.5–1.0 Bcf/d	Fully sold; potential capacity upsizing
Lake Charles LNG	Q2: SPAs with Chevron (3 mtpa total) and Kyushu; HOA with MidOcean (30%)	Advanced talks with Mid Ocean (30% equity); FID contingent on equity sell-down to 80% and converting HOAs to SPAs; disciplined returns required	Progress, but FID gated by equity/SPA milestones
NGL export & fractionation	Q2: Flexport ethane/propane online; ethylene service expected; Frac 9 in 2026	Flexport ramping; ethylene export-ready; ~95% LPG export capacity at Nederland contracted through decade	Utilization rising; export optionality locked
Crude logistics (Enbridge tie-ups)	—	100 kbpd Southern Illinois Connector FID; potential 250 kbpd via DAPL; aligns with DAPL re-contracting; keeps ETCOP/DAPL fuller	Positive structural fill for crude
Storage	Q2: Bethel cavern FID (doubling to >12 Bcf)	Storage rates expected to rise with LNG and reliability needs; potential to add at least 15 Bcf more at Bethel	Growing strategic value
Asset conversion optionality	—	Evaluating converting one Permian NGL pipeline to gas service given better returns vs tight NGL tariffs	High-return reconfiguration optionality

Management Commentary

“We now expect to be slightly below the lower end of [the] guidance range of $16.1–$16.5 billion.”
“We have entered into multiple agreements with Oracle to supply natural gas to three U.S. data centers…approximately 900,000 Mcf per day.”
“Within the last year, we have contracted over 6 Bcf per day of pipeline capacity with demand pull customers…weighted average life of over 18 years…more than $25 billion of revenue from firm transportation fees.”
“We are considering converting one of our NGL pipelines to natural gas service.”
“We will not proceed with LNG [Lake Charles] until we have secured 80% of equity partners…[and] convert HOAs to SPAs.”
“Flexport…is now ready for ethylene export service…We expect to have over 95% of all LPG export capacity at Nederland contracted through the end of this decade.”

Q&A Highlights

Guidance clarification: 2025 outcome “slightly below” the low end excludes any Parkland contribution from Sunoco; capex timing deferrals moved spend into 2026 .
Data-center economics: Many deals are low capital laterals leveraging existing systems; demand charges and storage-backed reliability create attractive returns; Hugh Brinson could be “the most profitable asset we’ve ever built” .
NGL-to-gas pipeline conversion: Competitive NGL tariffs and large gas demand could yield “twice the revenue” vs NGL in some scenarios; decision under study .
Crude strategy: With Enbridge, 100 kbpd Southern Illinois Connector FID and potential 250 kbpd via DAPL align with re-contracting and support long-term utilization with 15‑year agreements .
LNG FID: Requires 80% external equity and sufficient binding SPAs; capital discipline is paramount .

Estimates Context

Q3 2025 vs S&P Global consensus: Revenue $19.95B vs $21.81B* (miss); EPS $0.28 vs $0.331* (miss); EBITDA (S&P) $3.59B* vs $3.97B* (miss). Company-reported Adjusted EBITDA was $3.84B, pressured by one-time costs (e.g., Rover ad valorem, NGL remediation) and lapping prior-year business interruption proceeds .
Forward (near-term): Street models step-up in Q4 and Q1 (revenue $26.64B*, $24.75B*; EPS $0.367*, $0.362*; EBITDA $4.19B*, $4.23B*), consistent with Flexport ramp, Permian plant ramp, and partial-year timing of Hugh Brinson . Values marked * retrieved from S&P Global.

Values retrieved from S&P Global.

Key Takeaways for Investors

Near-term: Results missed consensus on revenue/EPS/EBITDA; guidance trimmed—expect estimate revisions down for FY25 EBITDA; watch for clarity on 4Q one-time noise vs run-rate .
Contracted growth: Fully contracted Desert Southwest and high data-center/power demand underpin multi‑year volume growth with long-duration, demand-pull contracts—supportive for multiple re-rating despite short-term misses .
2026 inflection: 2026 growth capex ~$5B targeting gas-directed projects; key ramps (Flexport, Frac 9, Permian plants, Hugh Brinson late 2026) should drive step-up in EBITDA .
Capital discipline: LNG FID remains contingent—limits downside risk from mega-project execution; reaffirms focus on returns .
Optionality/leverage to AI: Potential NGL-to-gas conversion and storage expansions could unlock higher returns as AI/datacenter-driven power demand scales .
Income support: Distribution raised to $0.3325/unit; strong liquidity with $3.44B revolver availability .
Trading setup: Watch catalysts—Desert Southwest upsizing decision, additional data center contracts disclosed as confidentiality eases, Lake Charles equity/SPAs progress, and crude tie-in volumes with Enbridge; these can shift sentiment positively even as FY25 guidance is trimmed .

Additional Relevant Press Releases (Q3 2025 context)

FourPoint Resources & Energy Transfer to double Price River Terminal export capacity (Utah) with new loading/storage infrastructure; in-service targeted 4Q26—supports Uinta Basin crude takeaway and ET’s downstream connectivity .
Parkland acquisition by Sunoco (ET holds SUN GP interest) closed Oct 31; management noted FY25 guidance commentary excluded Parkland effects .

Energy Transfer LP (ET)·Q3 2025 Earnings Summary