Energy Transfer (ET) Q1 2026 Earnings Transcript

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Date

Tuesday, May 5, 2026 at 9 a.m. ET

Call participants

• Co-Chief Executive Officer — Marshall McCrea
• Chief Financial Officer — Dylan Bramhall
• Co-Chief Executive Officer — Tom Long

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Takeaways

• Adjusted EBITDA -- $4.9 billion, up from $4.1 billion.
• Distributable Cash Flow (DCF), as adjusted -- $2.7 billion attributable to partners, compared to approximately $2.3 billion in the prior period.
• Record Segment Volumes -- Achieved highest-ever midstream gathering, NGL fractionation, NGL export, and crude oil transportation volumes.
• Organic Growth Capital Spending -- $1.5 billion deployed, focused on intrastate, NGL and refined products, midstream, and interstate segments, excluding Sun and USA Compression capital expenditures.
• 2026 Adjusted EBITDA Guidance -- Raised to $18.2 billion–$18.6 billion, up from $17.45 billion–$17.85 billion, reflecting a $750 million midpoint increase.
• 2026 Organic Growth Capital Guidance -- Updated to $5.5 billion–$5.9 billion, versus prior $5.0 billion–$5.5 billion, mainly due to additional growth projects, excluding Sun and USA Compression capital expenditures.
• NGL and Refined Products Adjusted EBITDA -- $1.2 billion, compared to $978 million, with gains from Gulf Coast operations and Mont Belvieu performance.
• Midstream Adjusted EBITDA -- $887 million, down from $925 million, impacted by lower commodity prices and absence of Winter Storm Uri revenue recognized in the prior period.
• Crude Oil Adjusted EBITDA -- $869 million, up from $742 million, due in part to rising crude prices and legacy contract recontracting.
• Interstate Natural Gas Adjusted EBITDA -- $519 million, compared to $512 million, driven by higher volume and rates on key pipelines.
• Intrastate Natural Gas Adjusted EBITDA -- $437 million, up from $344 million, with a $100 million benefit from winter storm conditions.
• Desert Southwest Pipeline Project -- Progressed FERC prefiling in March and anticipates filing a formal application in the fourth quarter, aiming for 2029 service.
• Springerville Lateral Project -- 120-mile, 30-inch pipeline, 625 million cubic feet per day capacity, $600 million expected capital, backed by 20-year contracts, targeting 2029 service.
• Hugh Brinson Pipeline Phase 1 -- Phase 1 expected in service in the fourth quarter, with potential early flows in the third quarter; Phase 2 anticipated in 2027 as fully contracted west-to-east backbone.
• Florida Gas Transmission Projects -- Two new projects with 15- to 25-year anchor shipper agreements; Phase 9 pipeline and compression to add 525 million cubic feet per day, South Florida project to add 230 million cubic feet per day, expected cost shares of $565 million and $110 million, with service dates in 2028 and 2030 respectively.
• Permian Processing Expansions -- Mustang Draw 1 (275 million cubic feet per day) commissioning for service next month; Mustang Draw 2 scheduled for fourth quarter service.
• Extended Ethane Export Contracts -- Most Nederland agreements extended to 2041, increasing long-term export visibility.
• Bayou Bridge Expansion -- Approved expansion to up to 600 thousand barrels per day, supported by a 10-year demand-pull contract, planned for first-quarter 2027 completion.
• Targeted Distribution Growth Rate -- Management reiterates long-term annual distribution growth goal of 3%–5% and leverage target of 4.0x–4.5x EBITDA.

Summary

Energy Transfer (NYSE:ET) reported a marked increase in adjusted EBITDA and segment volumes, with results driving higher full-year guidance. Management highlighted significant project progress across natural gas, NGL, and crude segments, including major contract-backed infrastructure expansions. Strategic execution was underscored by new and extended long-term agreements, as well as strengthened LNG and NGL export market positioning.

• Management stated, "our full-year optimization target in the first quarter," identifying roughly $300 million of the quarter's outperformance as one-time but recurring over several years for the company.
• The operating team cited continued demand growth linked to U.S. supply reliability, with Marshall McCrea noting a "very clear redirection to the U.S. for all products—LNG, NGLs, oil, etc."
• Firm agreements for Springerville, Hugh Brinson, and Florida Gas projects are expected to support durable cash flows over the next two decades.
• Ethane export contract extensions through 2041 at Nederland terminal signal a long-term commitment from counterparties and reinforce sustained international demand.
• Guidance midpoint assumptions remain conservative on commodity price stacks, with management indicating potential to achieve or exceed the high end if prices persist.

Industry glossary

• DUCs (Drilled but Uncompleted Wells): Oil or gas wells that have been drilled but are not yet completed or producing, representing latent production potential.
• FGT (Florida Gas Transmission): Interstate natural gas pipeline system providing transportation primarily to Florida markets, referenced for new expansion projects.
• FERC (Federal Energy Regulatory Commission): U.S. agency responsible for regulating interstate transmission of electricity, natural gas, and oil; project approvals require FERC applications.
• Bcf (Billion Cubic Feet): A volumetric measurement commonly used for natural gas quantities, denoting one billion cubic feet.
• MMBtu (Million British Thermal Units): Standard energy unit used to measure fuel volumes, such as natural gas, in the energy sector.

Full Conference Call Transcript

Let us start with our financial results for the first quarter of 2026. We generated adjusted EBITDA of approximately $4.9 billion compared to approximately $4.1 billion for the first quarter of last year. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2.7 billion compared to approximately $23 billion for the first quarter of 2025. These results were supported by strong operations, including record midstream gathering volumes, NGL fractionation volumes, NGL export volumes, and crude oil transportation volumes for the quarter. For 2026, we spent approximately $1.5 billion on organic growth capital, primarily in the intrastate, NGL and refined products, midstream, and interstate segments, excluding Sun and USA Compression CapEx. Turning to our 2026 guidance. As a result of our strong first quarter performance across our segments as well as revised expectations for the rest of 2026, we now expect our 2026 adjusted EBITDA to range between approximately $18.2 billion and $18.6 billion compared to the previous range of approximately $17.45 billion to $17.85 billion. This includes a beat of approximately $500 million and the capture of our full-year optimization target in the first quarter, as well as expectations for continued outperformance for the balance of the year. Now turning to organic growth capital guidance. We now expect 2026 organic growth capital to be between approximately $5.5 billion and $5.9 billion compared to our previous guidance of approximately $5.0 billion to $5.5 billion, excluding Sun and USAC. This increase is primarily a result of the addition of several new growth projects, including the construction of the new Springerville lateral off our existing Transwestern pipeline, the construction of pipelines and meter stations to provide natural gas to various power plants and data center sites in Oklahoma and Arkansas, accelerated timing on longer-term projects like Desert Southwest and FGT capital spend, and gathering system and compression buildout in the midstream segment, primarily in the Permian Basin associated with recent contract and acreage dedication extensions. I will provide additional details about these projects later in the call. Beyond these projects, we continue to have a significant backlog of opportunities that are expected to support future growth. Now turning to our results by segment for the first quarter, starting with NGL and refined products. Adjusted EBITDA was approximately $1.2 billion compared to approximately $978 million for the first quarter of 2025. We saw higher throughput across our Gulf Coast pipeline operations and record performance at our Mont Belvieu fractionators. In addition, new chilling capacity placed into service last year contributed to a $50 million increase in earnings, as well as record export volumes from our Nederland terminal in the first quarter. This more than made up for fog delays experienced in the first quarter of 2025. During the first quarter of 2026, we realized higher gains of $65 million due to the timing of the settlement of NGL and refined product inventory hedges, which offset losses realized in the first quarter of 2025. Results for the quarter also included an increase of approximately $50 million from higher premiums from the sale of propane and butane for both export and domestic supply, as well as approximately a $25 million increase due to inventory writedown losses realized in the first quarter of last year. For Midstream, adjusted EBITDA was approximately $887 million compared to approximately $925 million for the first quarter of 2025. Base business earnings increased primarily due to growth in the Permian Basin where we saw volumes up 8% related to new and upgraded processing plants brought online since the first quarter of last year. In addition, we saw a $25 million decrease due to lower NGL and natural gas prices compared to last year. As a reminder, the first quarter of last year included the recognition of revenue of $160 million from Winter Storm Uri. For the crude oil segment, adjusted EBITDA was approximately $869 million compared to approximately $742 million for the first quarter of 2025. During the quarter, we saw continued growth across several of our crude oil pipeline and gathering systems. Results also included a $60 million increase related to favorable impacts to our crude oil inventory value as a result of rising crude oil prices. We expect these gains to be mostly offset with hedge losses during the second quarter of this year. In addition, we recognized $43 million of revenue that had previously been reserved related to the recontracting and extension of a legacy shipper contract during the recently completed successful DAPL open season, and we had lower expenses due to a $43 million adjustment to an accrual for a litigation-related contingency. In our interstate natural gas segment, adjusted EBITDA was approximately $519 million compared to approximately $512 million for the first quarter of 2025. This increase was primarily due to higher contracted volumes and higher rates on several of our pipelines including Panhandle Eastern, Trunkline, Florida Gas, and Transwestern. And for our intrastate natural gas segment, adjusted EBITDA was approximately $437 million compared to approximately $344 million in the first quarter of 2025. This was primarily due to an increase of approximately $100 million from winter storm burn. Results for the first quarter show how incredibly well-positioned our assets are across the country. Combining our extensive pipeline network, our storage facilities, and our terminals with our exceptionally experienced optimization and operating teams, we were able to capitalize on quickly changing dynamics and market volatility. For a closer look at some of our major projects on the natural gas side of our business, where we continue to see significant demand for our services: We are making good progress on our Desert Southwest pipeline project. In March 2026, Transwestern Pipeline initiated the FERC prefiling process for the project as previously scheduled, and we expect to file the formal certificate application with FERC in the fourth quarter of this year. In April, as a continuation of our comprehensive stakeholder engagement program, we hosted 15 open houses in communities along the entire proposed pipeline route throughout Texas, New Mexico, and Arizona. Our teams continue to actively engage with elected officials, county leadership, landowners, and associated communities along the route to communicate project information and updates; we have engaged with over 500 stakeholders to date.

Our discussions have continued to be very positive as existing and potential stakeholders learn more about the expected economic benefits, realize the critical need for a dependable supply of natural gas to help with the transition from coal generation to natural gas–fired generation, and to help address significant power needs in the coming years driven by population and demand growth in Arizona and New Mexico markets. We expect this pipeline to be in service providing a reliable energy source by 2029.

On the existing Transwestern pipeline, we recently approved the construction of the new Springerville lateral, an approximately 120-mile, 30-inch pipeline that will have a capacity of approximately 625 million cubic feet per day and extend south to new natural gas power generation that is expected to replace two coal-fired plants. This project is backed by 20-year agreements and is expected to be in service in 2029. Total growth capital for this project is expected to be approximately $600 million. New construction on our Hugh Brinson pipeline is going well.

We continue to expect Phase 1 to be in service in the fourth quarter of this year upon the full buildout of the 400-mile pipeline and associated compression required to move 1.5 Bcf per day of gas to customers’ contractual delivery points. However, if we stay on our current schedule, we will have the ability to begin flowing some gas early in the third quarter, which is prior to placing Phase 1 into service. We continue to expect Phase 2, which includes additional compression, to be in service in 2027. The pipe is fully contracted from west to east, and we also have a growing amount of backhaul volumes committed that are expected to add significant upside.

Turning to Florida Gas Transmission, or FGT. In February, we completed open seasons for two new projects that are supported by 15- to 25-year long-term agreements with anchor shippers. The Phase 9 project is designed to expand firm gas transportation capacity to multiple new and existing meter stations located across FGT’s market area. This project will consist of the construction of approximately 90 miles of pipeline looping as well as new and upgraded compression, with an anticipated capacity of approximately 525 million cubic feet per day. We recently locked in pipe for delivery in 2027 and compression for delivery in 2028, and we continue to expect the project to be available for service in the fourth quarter of 2028.

The South Florida project is designed to enhance the reliability of critical infrastructure and increase overall deliveries in South Florida. The project has a condition precedent but, once we reach FID, it will consist of the construction of an approximately 40-mile extension with a capacity of approximately 230 million cubic feet per day, along with compression and a new meter station, and is expected to be available for service in 2030. Energy Transfer LP’s share of the cost for these two projects is expected to be approximately $565 million and approximately $110 million respectively, depending upon final shipper volume elections. We continue to make progress on a new storage cavern at our 12 Bcf facility.

In February, our intrastate power team added connections to serve three new power plant loads in the state of Oklahoma. We have since added a fourth connection for a total of approximately 300 million cubic feet per day of new gas supply. The first of these connections is in service, with two more expected in service in the third quarter of this year. The remaining connection is expected to be in service in 2028. These connections are supported by long-term contracts with investment-grade counterparties. In addition, we have entered advanced negotiations to serve another 400 million cubic feet per day of new power plant demand in Oklahoma.

Since our last earnings call, Energy Transfer LP has entered into agreements to provide long-term firm natural gas transportation services through our Texas intrastate system to support the Nexus Hubbard campus located in Central Texas, where Nexus is constructing a behind-the-meter AI hyperscale campus powered by on-site natural gas generation. Initial volumes are expected to be approximately 150 million cubic feet per day with certain rights by the transporter to increase its capacity upon election. Costs associated with this project are expected to be fully reimbursed, and it is expected to be in service by the end of this year.

In addition, we recently entered into firm natural gas transportation service through our EGT pipeline to support a new data center site in Arkansas. The facility is expected to be in service in mid-2027. Energy Transfer LP also previously entered into a 20-year binding agreement with Intergic Louisiana to provide at least 250 thousand MMBtus per day of firm transportation service to fuel their facilities in Richland Parish, Louisiana.

To facilitate flow of this gas, we plan to construct an 18-mile lateral off of our Tiger Pipeline, for which our customer recently exercised their option to upsize the pipeline lateral to 36 inches, and they continue to have an option to increase their commitment to up to 1 Bcf per day. In addition to these projects, we have multiple ongoing discussions with power plants to provide significant volumes and associated transportation revenues across 15 states, which have a high likelihood of reaching FID.

Now looking at our Permian processing expansions, the 275 MMcf per day Mustang Draw 1 processing plant is currently being commissioned and is expected to be in full service next month, and we expect volumes to ramp up quickly. We continue to expect our 275 MMcf per day Mustang Draw 2 plant to be in service in the fourth quarter of this year. In our NGL segment, we placed the Gateway NGL pipeline debottleneck project into service in the first quarter of this year, providing increased deliveries of Delaware Basin liquids to Energy Transfer LP’s NGL fractionation complex in Mont Belvieu.

Construction is also underway on a new 3 million barrel ethane storage cavern at Energy Transfer LP’s NGL fractionation complex at Mont Belvieu. The cavern, which is expected to be in service in 2027, will help support our ninth fractionator at Mont Belvieu that is expected to be in service in the fourth quarter of this year, as well as future ethane export expansions. At Nederland, we have recently extended the vast majority of our ethane export agreements into 2041, adding 10 years to the current contracts. We are hopeful to be in position for incremental Nederland ethane expansion in the coming months.

In our crude oil segment, we continue to work with Enbridge on a project to provide capacity for approximately 250 thousand barrels per day of light Canadian crude oil through our system. In addition, we have approved an expansion of the Bayou Bridge crude oil pipeline, which is expected to increase the capacity to up to approximately 600 thousand barrels per day depending on destination and product mix. This expansion is underpinned by a 10-year term extension and volume increase from a demand-pull customer and is expected to be in service in the first quarter of 2027.

As you can see, we had a lot of great things happen in the first quarter and many more exciting things on the way, which contributed to our increased EBITDA guidance for 2026. Our guidance each year is based upon expectations for the base business, with minimal optimization included. However, in five of the last eight years, we have seen large spreads, optimization, and other opportunities that have provided significant upside to our base business. These kinds of benefits, while one-time in nature, highlight the unique ability of our business to consistently capture significant upside during market volatility.

While additional upside is expected to be dependent upon the duration and impact of current market disruption and resulting commodity prices, our assets remain incredibly well-positioned to continue maximizing these opportunities. As a result, we are optimistic that some of the benefits we saw in the first quarter will carry over throughout the rest of the year, putting us in a position to achieve or exceed the high end of our guidance range. Additionally, we continue to expect the ramp-up of growth projects, including our FlexPort NGL export project, new Permian processing plants, Hugh Brinson, and others, which we expect will contribute to continued growth in 2026.

In particular, as our Hugh Brinson pipeline is in service, it will be extremely well-positioned to become a major U.S. header system that ties together our network of large-diameter pipelines, providing significant future upside. Our large slate of growth projects is contracted under long-term commitments and expected to generate mid-teen returns and considerable earnings growth over the next decade or more. Completing these projects safely, on time, and on budget remains one of our top priorities for 2026.

We also continue to see new growth opportunities across all aspects of our business, demonstrated by the announcement of several new projects this quarter, and we remain extremely well-positioned to help meet the substantial growth in demand for energy resources over many years to come. As a result, we also remain very focused on capital discipline, targeting a long-term annual distribution growth rate of 3% to 5% and maintaining our leverage target of 4.0x to 4.5x EBITDA.

In summary, because of the breadth of our assets, we have an unparalleled ability to transport large amounts of energy from all of the major supply basins to markets throughout the U.S., including major trading hubs, power plants, data centers, city gates, industrial complexes, and other downstream markets, including international markets through our export terminals. This concludes our prepared remarks. Operator, please open the line for our first question.

Operator: Thank you. We will now begin the question-and-answer session. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. We will pause momentarily to assemble the roster. We have the first question from Michael Blum with Wells Fargo. Please go ahead.

Michael Blum: Thanks. Good morning, everyone. Wanted to start high level in light of the Middle East conflict that is ongoing. Are you seeing any change in U.S. producer activity or messaging? And in a similar vein, would you expect to see any permanent shifts in where global buyers will be sourcing their hydrocarbons, perhaps leaning more heavily on the U.S.? And are you seeing any of that in your discussions yet?

Marshall McCrea: Good morning, Michael. As I look around the room, there are several people who want to answer because we are so excited about where we sit and where our assets sit. Given what has been going on in the world, there is a very clear redirection to the U.S. for all products—LNG, NGLs, oil, etc.—and it really emphasizes the value of what this country offers and, more importantly, what our partnership offers to deliver these products around the world. If you talk about individual basins, it is all different, but the major tenor throughout is optimism.

It is not a rush to put a bunch of rigs in, but even as of yesterday, one of our bigger customers in the Midland Basin, Diamondback, announced they are going to upsize and bring in more rigs. We think it will be a slow-moving pickup, not a lot of talk, but evident that we will see more rigs as more countries and companies turn to the U.S. for supply regardless of how long the war may last. An example in North Louisiana, the Haynesville: we are projecting about 800,000 Mcf of growth into our processing, treating, and downstream assets by August or September.

Clearly, producers in North Louisiana are drilling and will bring on DUCs as we proceed deeper into this year, and we think that will continue for many years. We love where our assets are and are very excited about the future of drilling growth. It is not clear how quickly all companies and all basins will pick up, but the bottom line is there will be increased drilling and bringing on new wells from DUCs throughout the country, and we are very excited about where we sit.

Michael Blum: Thanks for that, Marshall. Appreciate it. On LPG exports, can you remind us what percent of your capacity is contracted versus open? Are you seeing any increase in demand for contracted capacity? And do you think length of contracts or rates could trend higher over time?

Marshall McCrea: Yes to all of the above. As mentioned earlier, whether with companies building assets here or buying products here, everybody is turning to the U.S., and we are extremely well-positioned. Our strategy is long-term. Whether LPG or natural gas, we are looking to extend into the 2030s and 2040s where possible. Our team did a great job at healthy rates extending our LPG business well into the 2030s. We do not have a lot of spot; we have four or five ship slots where we could be printing more money, but we do have some spots available at the FlexPort project that we just completed and are ramping.

We have at least one or two slots a month that can benefit from higher spreads. We do think this environment will bring about longer terms and stronger margins over time as everyone leans on the U.S. for supply.

Operator: Thank you. We have the next question from Gabriel Moreen with Mizuho. Please go ahead.

Gabriel Moreen: Good morning, team. On guidance, in the slides you did not shift your allocation between fee-based and commodity-based margin through the year, and you are using the forward curves. On the other hand, you noted you are hopeful to exceed the upper end of guidance if things persist. Can you talk about the moving pieces, assumptions on commodity versus forward curve, and what you are baking in for the rest of the year?

Dylan Bramhall: We had an incredible first quarter. We beat our internal plan by approximately $500 million and achieved our full-year optimization earnings target. Of that $500 million, about $300 million would probably be considered one-time. We call it one-time, but we see this almost every year at Energy Transfer LP because of our assets and people. The rest is a result of tailwinds to the business. We raised guidance by $750 million at the midpoint based on line-of-sight continued outperformance across most segments—volumes, rates, and spreads. The conflict in the Middle East has made clear, as Marshall pointed out, the need for reliable U.S. energy supplies, increasing demand, volumes, and rates.

We pray for a resolution, but we believe supply and product flows will take an extended time to normalize and likely will not return to the pre-conflict pattern, similar to what we saw with the Ukraine conflict. For the balance of the year, the midpoint of our guidance range assumes a conservative commodity price stack going forward. If prices remain anywhere near where they are now, that will push us to the high end of the guidance range and potentially allow us to exceed it.

Gabriel Moreen: Thanks. As a follow-up on Desert Southwest and the Springerville lateral, were the Springerville volumes contemplated in the original 2.3 Bcf/d on Desert Southwest, or is there potentially upsizing to the base project? Any potential for further laterals? And has anything changed on the regulatory approval or timeline given the lateral associated with the project?

Marshall McCrea: The Springerville lateral is tied to the retirement of some coal plants and replacement with natural gas–fired generation. We believe the majority of that gas will come from either the San Juan Basin or the Permian Basin. There are other lateral opportunities off that, and we are constantly evaluating them. Separately, on Desert Southwest, throughout New Mexico and especially in Arizona, there are numerous opportunities to lay laterals to different power plants and customers. We are chasing a lot of demand and have zero concerns about selling the remaining portion of that gas through what will be the largest pipeline built in the U.S. once completed. As always, we will add value on assets already in the ground.

The Springerville customers can ultimately source gas from anywhere on the TW system, but the vast majority will come from the Permian Basin or San Juan.

Operator: We are not showing any further questions at this time. I will now turn the call back to Tom Long for any closing remarks.

Tom Long: Thank you, everyone, for joining today. As you heard, we have a lot of great projects underway and a strong outlook, not just for the quarter we reported but for many years to come. Our projects are supported by long-term contracts with a healthy mix of demand-side customers, many with terms extending beyond 20 years. This supports why we remain optimistic and excited about our future. We look forward to following up with you on any additional questions.

Operator: That concludes today’s conference call. You may now disconnect.

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