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    Earnings call· Jun 2025(Q2 FY25)

    Energy Transfer Q2 FY25 earnings call ET

    Aug 6, 2025 Source

    Executive summary

    Energy Transfer Q2 FY25 — Strategic Project FIDs and Revised EBITDA Guidance

    Energy Transfer reported a mixed Q2 FY25, with overall adjusted EBITDA growth driven by strong midstream and interstate gas performance, but offset by weakness in NGL, crude, and intrastate gas segments. The company announced significant FIDs for natural gas infrastructure, including the Desert Southwest pipeline and Hugh Brinson Phase 2, alongside NGL export and processing expansions. Management revised its full-year adjusted EBITDA guidance downwards, citing specific regional and market headwinds, while expressing strong confidence in its long-term growth trajectory from these new projects and demand from power generation and data centers.

    Highlights

    5

    • Adjusted EBITDA increased to $3.9 billion in Q2 FY25 from $3.8 billion in Q2 FY24.

    • Midstream segment adjusted EBITDA grew to $768 million from $693 million YoY, driven by 10% higher Permian volumes.

    • Interstate natural gas segment adjusted EBITDA increased to $470 million from $392 million YoY due to higher contracted volumes.

    • Desert Southwest pipeline project announced with 1.5 Bcf/day capacity, expected in-service by Q4 2029, backed by long-term commitments.

    • Flexport NGL Export Expansion Project placed into ethane and propane service, expected to add up to 250,000 bbl/day total NGL export capacity.

    Concerns

    5

    • Adjusted EBITDA guidance for FY25 revised to be at or slightly below the lower end of the $16.1 billion to $16.5 billion range.

    • NGL and refined products adjusted EBITDA decreased to $1 billion from $1.1 billion YoY due to lower optimization gains and blending margins.

    • Crude oil segment adjusted EBITDA decreased to $732 million from $801 million YoY, primarily due to lower Bakken pipeline transportation revenues.

    • Intrastate natural gas adjusted EBITDA decreased to $284 million from $328 million YoY due to reduced pipeline optimization.

    • Slower recovery in dry gas areas and lack of normal volatility in gas optimization business contributed to revised guidance.

    Guidance & targets

    14
    CategoryTargetConfidence
    Adjusted EBITDA
    At or slightly below the lower end of $16.1 billion to $16.5 billion
    high materiality
    High
    Organic growth capital spend
    Approximately $5 billion
    high materiality
    High
    Growth project earnings contribution
    Majority of upcoming earnings growth
    medium materiality
    High
    Desert Southwest pipeline in-service date
    No later than Q4 2029
    high materiality
    High
    Hugh Brinson Pipeline Phase 1 in-service date
    No later than Q4 2026
    medium materiality
    High
    Hugh Brinson Pipeline contracted capacity
    More than 2.2 Bcf per day contracted
    medium materiality
    High
    Bethel natural gas storage cavern in-service date
    Late 2028
    low materiality
    High
    Mustang Draw processing plant in-service date
    Q2 2026
    low materiality
    High
    Flexport NGL Export Expansion Project ethylene export services
    Q4 this year
    medium materiality
    High
    Flexport NGL Export Expansion Project ramp-up
    Ramp up throughout the remainder of 2025
    medium materiality
    High
    NGL pipeline looping in-service date
    First half of 2027
    low materiality
    High
    Lake Charles LNG equity sell-down
    Reduce Energy Transfer's ownership to approximately 25%
    high materiality
    High
    Lake Charles LNG contracted capacity target
    15 million metric tons per annum
    high materiality
    High
    Natural gas-fired electric generation facilities in-service
    2 more facilities by year-end, remainder in 2026
    low materiality
    High

    Segment performance

    5
    SegmentRevenueYoYQoQMargin
    NGL and refined products
    Adjusted EBITDA decreased from $1.1 billion in Q2 2024, primarily due to lower gains from optimization of hedged NGL and refined product inventories and lower blending margins, partially offset by higher throughput across Mariner East and Gulf Coast pipeline operations and fractionation facilities.
    		———$1 billion
    Midstream
    Adjusted EBITDA increased from $693 million in Q2 2024, driven by higher legacy volumes in the Permian Basin due to processing plant upgrades and increased plant utilization, as well as the addition of WTG assets in July 2024. This was partially offset by lower gathering volumes in dry gas areas.
    Permian Basin legacy volumes: up 10%
    		———$768 million
    Crude oil
    Adjusted EBITDA decreased from $801 million in Q2 2024, offset by growth across several crude pipeline systems and contributions from the Permian joint venture with SUN. This was primarily due to lower transportation revenues on the Bakken pipeline.
    		———$732 million
    Interstate natural gas
    Adjusted EBITDA increased from $392 million in Q2 2024, primarily due to higher contracted volumes on several interstate pipeline systems.
    		———$470 million
    Intrastate natural gas
    Adjusted EBITDA decreased from $328 million in Q2 2024. Increased volumes across the Texas intrastate pipeline system due to third-party volume growth were offset by reduced pipeline optimization from shifts to more long-term third-party contracts and price spreads.
    		———$284 million

    Operational metrics

    14
    Adjusted EBITDA
    $3.9 billionvs $3.8 billion in Q2 FY24
    Q2 FY25

    Company-wide adjusted EBITDA.

    Distributable cash flow attributable to partners (as adjusted)
    $2 billion
    Q2 FY25

    Non-GAAP financial measure.

    Organic growth capital spend
    $2 billion
    First 6 months of 2025

    Capital spent on organic growth projects.

    Permian Basin processing capacity added
    800 MMcf/day
    Last year

    Includes new plants and optimizations at existing facilities.

    Permian Basin processed volumes
    Nearly 5 Bcf/dayNew record
    Recently

    Reached a new record.

    Y-grade transportation throughput from Permian
    New record
    Recently

    Reached a new record.

    NGL export capacity
    1.4 million bbl/day
    Current

    One of the largest NGL businesses in the United States.

    Natural gas pipeline network length
    More than 105,000 miles
    Current

    One of the largest natural gas pipeline networks in the United States.

    U.S. natural gas production moved
    Approximately 30%
    Current

    Percentage of U.S. natural gas production moved by Energy Transfer.

    Gas-fired power plants connected
    Nearly 200
    Current

    Number of gas-fired power plants connected to the network.

    Growth project returns
    Mid-teen returns
    Future

    Expected on a majority of growth projects.

    Desert Southwest pipeline EBITDA multiple
    6x
    Projected

    Analyst-confirmed estimate for the project's EBITDA multiple.

    Hyperscaler behind-the-meter contract
    380,000 Dth/dayIncreased from 80,000 Dth/day
    Current

    One of three hyperscaler deals signed in Texas, showing significant expansion.

    Bakken volume impact
    50,000 bbl/day less
    Q2 FY25

    Impact from various factors including TMX expansion, weather, and fires.

    Industry KPIs

    6
    MetricValueDetails
    Pipeline throughput storageNearly 5 Bcf/dayBcf/day
    Sanctioned expansion backlog$5.3 billionUSD
    Basin level production volumeUp 10%%
    Take or pay contract structure380,000 Dth/dayDth/day
    Weather event volume earnings impact50,000 bbl/day lessbbl/day
    Distributable cash flow per unit share$2 billionUSD

    Deals & partnerships

    4
    MidOcean EnergyNonbinding framework for joint development of Lake Charles LNG project

    Signed an HOA (Heads of Agreement) for the Lake Charles LNG project.

    Kyushu Electric Power CompanyLong-term LNG Sale and Purchase Agreement (SPA)20-year

    Signed a 20-year SPA for Lake Charles LNG.

    Chevron USALong-term LNG Sale and Purchase Agreement (SPA)20-year

    Signed a 20-year SPA for Lake Charles LNG.

    SUNPermian joint venture

    Recently formed joint venture contributing to crude oil segment results.

    Capital programs

    11
    Desert Southwest pipeline projectunderway$5.3 billion

    Benefit: 1.5 Bcf/day transportation capacity

    Strategic expansion of Transwestern pipeline, includes $600 million AFUDC. Backed by significant long-term commitments with investment-grade counterparties. Open season expected later this quarter, with potential for efficient expansion to a 48-inch pipeline.

    Hugh Brinson Pipeline Phase 1underway

    Benefit: 1.5 Bcf/day natural gas takeaway

    Expected to provide natural gas takeaway from the Permian Basin.

    Hugh Brinson Pipeline Phase 2sanctioned

    Benefit: 2.2 Bcf/day (west to east) / 1 Bcf/day (east to west) bidirectional capacity

    Reached positive FID, includes addition of compression, establishing bidirectional capabilities and significant optionality for Texas markets.

    Bethel natural gas storage cavern expansionapproved$140 million

    Benefit: Double working gas storage capacity to over 12 Bcf

    New storage cavern to serve growing demand in the intrastate natural gas pipeline network.

    SESH pipeline expansionapproved

    Benefit: Serve growing power generation needs

    Expansion to serve the Southeastern region of the United States.

    Lenorah 2 processing plantcompleted

    Benefit: 200 MMcf/day processing capacity

    Placed into service in the Midland Basin in Q2 2025, currently running at full capacity.

    Badger processing plantcompleted

    Benefit: 200 MMcf/day processing capacity

    Recently placed into service, utilized a previously idle plant relocated to the Delaware Basin. Volumes are ramping up and expected to be at full capacity in the next few months.

    Mustang Draw plantunderway

    Processing plant expected to be in service in the second quarter of 2026.

    Flexport NGL Export Expansion Projectunderway

    Benefit: Up to 250,000 bbl/day total NGL export capacity

    At Nederland terminal, placed into ethane and propane service, ethylene export services expected Q4 2025. Fully contracted beginning January 2026, capacity split 50-50 between ethane/ethylene and propane.

    NGL pipeline looping (upstream of Lone Star Express)approved$60 million

    Benefit: Incremental 150,000 bbl/day of NGLs

    To expand access to NGLs from the Northern Delaware Basin.

    Natural gas-fired electric generation facilitiesunderway

    Benefit: 10-megawatt per facility

    Construction continues; second facility serving Badger processing plant recently commissioned, 2 more expected by year-end 2025, remainder in 2026.

    Risks & headwinds

    6
    Weakness in Bakken regionQ2 FY25 and expected for remainder of FY25

    Contributed to revised FY25 adjusted EBITDA guidance

    Mitigation: Evaluating open season with Enbridge for Canadian egress, potential for increased capacity on Dakota Access pipeline, long-term bullish outlook for Bakken.

    Slower recovery in dry gas areasQ2 FY25 and expected for remainder of FY25

    Contributed to revised FY25 adjusted EBITDA guidance

    Mitigation: Focus on new natural gas opportunities for power plants and data centers, leveraging extensive pipeline network.

    Lack of normal volatility in gas optimization businessQ2 FY25 and expected for remainder of FY25

    Contributed to revised FY25 adjusted EBITDA guidance

    Mitigation: Shifting to more long-term third-party contracts, expanding storage capacity (Bethel cavern) to benefit from pricing volatility.

    Slower growth in Permian crude businessYear-to-date FY25

    Contributed to revised FY25 adjusted EBITDA guidance

    Mitigation: Focus on Permian processing expansions (Lenorah 2, Badger, Mustang Draw) and NGL pipeline looping to capture growth.

    Lower gains from NGL and refined product optimization and blending marginsQ2 FY25

    Adjusted EBITDA decreased by $100 million YoY in NGL and refined products segment

    Mitigation: Focus on Flexport NGL Export Expansion Project to increase export capacity and contract volumes.

    Impact of TMX expansion and Canadian crude dynamics on BakkenQ2 FY25

    50,000 bbl/day less volume in Q2 FY25 for Bakken

    Mitigation: Anticipate volumes returning as Canadian egress capacity fills, exploring opportunities with Enbridge to help Canadian producers and potentially increase Dakota Access capacity.

    What to watch in Q3 FY25

    5

    Hyperscaler contract announcements

    Next quarters
    Current3 deals signed in Texas, one expanded to 380,000 Dth/day
    TargetMore discrete announcements on new data center and/or power plant deals

    Why it matters

    New hyperscaler and power plant deals represent a significant growth vector for natural gas demand and ET's pipeline network.

    We're pretty excited about what we anticipate announcing over these coming quarters.

    Q&A highlights

    6

    Can you provide more detail on commercialization efforts for gas-to-power for data centers, gating factors, scale of opportunities, and expected announcement timing?

    Management expressed excitement about data center opportunities, noting they are large-scale facilities requiring time to develop. They confirmed signing three deals in Texas, including one hyperscaler contract that expanded from 80,000 Dth/day to 380,000 Dth/day, with potential for 475,000 Dth/day. They anticipate more announcements in coming quarters but refrained from specific timelines due to varying project complexities.

    “We did sign our first kind of significant deal with a hyperscaler, a behind-the-meter hyperscaler here in Texas. It was 80,000 a day. We have recently, as of now, today increased that to 380,000 a day with the [ flex right ] to go to 475, maybe more upside from that from this one area in Texas. But it's just one of -- we've signed 3 deals now in Texas.”

    asked by Theresa Chen · answered by Marshall McCrea

    3 min read6 chapters

    Detailed Narrative

    01

    Strategic Natural Gas Infrastructure Expansion

    Energy Transfer announced the Desert Southwest pipeline project, a 516-mile, 42-inch pipeline designed to transport 1.5 Bcf/day from the Permian Basin to the Phoenix area. This $5.3 billion project, including $600 million AFUDC, is expected in service by Q4 2029 and is backed by long-term commitments. The company is also evaluating an expansion to a 48-inch pipeline to potentially double capacity due to strong demand. Additionally, Phase 2 of the Hugh Brinson Pipeline, including compression, reached FID, making the system bidirectional with 2.2 Bcf/day west-to-east and 1 Bcf/day east-to-west capacity, expected to be over 2.2 Bcf/day contracted upon service.

    02

    Permian Basin Processing and NGL Growth

    The company placed the 200 MMcf/day Lenorah 2 processing plant in the Midland Basin into service, now running at full capacity. The 200 MMcf/day Badger processing plant, utilizing a relocated idle plant, also commenced operations and is ramping up. These additions, along with 200 MMcf/day of optimizations, have increased Permian processing capacity by 800 MMcf/day over the last year, pushing total processed volumes to a new record of nearly 5 Bcf/day. The Mustang Draw plant is still expected in service in Q2 2026.

    03

    NGL Export and Transportation Enhancements

    The Flexport NGL Export Expansion Project at the Nederland terminal has begun ethane and propane service, with ethylene export services expected by Q4 2025. This project will ramp up to 250,000 bbl/day of total NGL export capacity by the end of 2025, fully contracted from January 2026. An NGL pipeline looping project upstream of the Lone Star Express Pipeline was approved, costing $60 million and expected in service in H1 2027, to source an incremental 150,000 bbl/day of NGLs from the Northern Delaware Basin.

    04

    Lake Charles LNG Commercialization Progress

    Lake Charles LNG continues to advance towards FID, having signed an HOA with MidOcean Energy for 30% of LNG production (approximately 5 mtpa) and 20-year SPAs with Kyushu Electric Power Company and Chevron USA. The company is in advanced discussions for the remaining capacity to reach its target of 15 mtpa, with some potential offtake customers also interested in project equity. Energy Transfer plans to sell down its ownership in the project to approximately 25% to reduce external financing requirements.

    05

    Data Center and Power Generation Demand

    Energy Transfer is actively pursuing opportunities related to growing demand from gas-fired power plants and data centers. The company has signed three deals in Texas with hyperscalers, including one that expanded from 80,000 Dth/day to 380,000 Dth/day, with potential for 475,000 Dth/day. Management highlighted its extensive natural gas pipeline network and storage capabilities as a key advantage for serving these demand-pull customers, with further announcements anticipated in coming quarters.

    06

    Bakken and Market Volatility Impacts

    The company's revised FY25 adjusted EBITDA guidance reflects weaker-than-expected performance in the Bakken region, slower recovery in dry gas areas, and reduced volatility in the gas optimization business. Management noted that Bakken volumes were impacted by TMX expansion, cold weather, and fires, leading to a 50,000 bbl/day reduction in Q2. Despite this, the company remains bullish on Bakken's long-term prospects, citing an open season with Enbridge to help Canadian producers and potential for increased capacity on its Dakota Access pipeline.

    AI-generated summary of the company’s earnings call. Not investment advice.