Energy Transfer LP Q1 FY2026 earnings call

Tom Long started by discussing financial results. They generated adjusted EBITDA of ~$4.9B vs ~$4.1B in Q1 2025. DCF attributable to partners was ~$2.7B vs ~$23B in Q1 2025. 2026 adjusted EBITDA guidance revised to $18.2B - $18.6B vs previous $17.45B - $17.85B. Organic growth capital guidance revised to $5.5B - $5.9B vs previous $5.0B - $5.5B. Discussed various projects like Desert Southwest pipeline, Springerville lateral, Hugh Brinson pipeline, Florida Gas Transmission projects, Permian processing expansions, NGL segment projects, crude oil segment projects.

For the first quarter of 2026, adjusted EBITDA was approximately $4.9 billion. By segment: NGL and refined products had adjusted EBITDA of approximately $1.2 billion (compared to $978 million in Q1 2025); Midstream had ~$887 million (vs ~$925 million in Q1 2025); Crude oil segment had ~$869 million (vs ~$742 million in Q1 2025); Interstate natural gas segment had ~$519 million (vs ~$512 million in Q1 2025); Intrastate natural gas segment had ~$437 million (vs ~$344 million in Q1 2025).

2026 adjusted EBITDA expected to range $18.2B - $18.6B, up from previous range. Organic growth capital expected $5.5B - $5.9B, up from previous. Expect continued outperformance due to strong Q1 and new projects. Ramp-up of growth projects like Hugh Brinson, FlexPort NGL export, etc. Optimistic some Q1 benefits carry over and can exceed guidance high end.

Q: 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?

A: 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.

Q: 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?

A: 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.

Q: 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?

A: 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.

Q: 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?

A: 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.