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DATE

Tuesday, February 17, 2026 at 9:00 a.m. ET

CALL PARTICIPANTS

  • Co-Chief Executive Officer — Thomas E. Long
  • Co-Chief Executive Officer — Marshall S. McCrea
  • Chief Financial Officer — Dylan A. Bramhall
  • [Senior Leadership Team Member] — Adam [surname not stated]

TAKEAWAYS

  • Adjusted EBITDA (Full Year) -- $16 billion, up 3%, and a partnership record, compared to $15.5 billion in the prior year.
  • Distributable Cash Flow (Full Year) -- $8.2 billion, down from $8.4 billion.
  • Adjusted EBITDA (Q4) -- Approximately $4.2 billion, up from $3.9 billion.
  • DCF Attributable to Partners (Q4) -- Approximately $2 billion, in line with the prior-year quarter.
  • Organic Growth Capital (2025) -- Approximately $4.5 billion, focused mainly on NGL, refined products, midstream, and intrastate segments; Sunoco LP and USA Compression excluded.
  • NGL & Refined Products Adjusted EBITDA (Q4) -- $1.1 billion, flat versus prior year; included a $56 million positive impact from a regulatory order, offset by a $58 million hedge settlement timing loss and $14 million from loading delays due to fog, with those negative impacts expected to be recovered in 2026.
  • Midstream Adjusted EBITDA (Q4) -- $720 million, up from $705 million, primarily on Permian, Northeast, and Ark-La-Tex region volume growth, partly offset by $14 million intersegment expense increase.
  • Crude Oil Adjusted EBITDA (Q4) -- $722 million, down from $760 million, reflecting a $19 million regulatory order benefit and lower Bakken Pipeline transportation revenue.
  • Interstate Natural Gas Adjusted EBITDA (Q4) -- $523 million, up from $493 million, on higher sold capacity and pipeline utilization.
  • Intrastate Natural Gas Adjusted EBITDA (Q4) -- $355 million, up from $203 million, driven by pipeline/storage optimization and increased Texas intrastate volumes.
  • Organic Growth Capital Guidance (2026) -- $5.0 billion–$5.5 billion, with around two-thirds targeted at natural gas assets and about one-quarter allocated to NGL and refined products projects.
  • Major Projects Pipeline -- Desert Southwest pipeline expanded to 48 inches for up to 2.3 Bcf/d capacity and expected completion by 2029 at a projected $5.6 billion cost.
  • Hugh Brinson Pipeline -- 100% of pipe delivered, mainline 75% complete, Phase 1 in service expected Q4 2026, with ability to flow early volumes; Phase 2 expected in Q1 2027, fully contracted for west-to-east flows at 2.2 Bcf/d.
  • FGT Expansion -- Phase IX to add up to 550 MMcf/d by Q4 2028; South Florida project, a new 37-mile lateral, targeted for 2030 service; ET’s portion of costs up to $535 million and $110 million, respectively, subject to final volumes.
  • Backlog Conversion -- 6 Bcf/d of pipeline capacity contracted with demand-pull customers in past year, spanning end users, data centers, and utilities.
  • NGL Mix -- 60% of Permian NGL pipeline/fractionation volumes are from owned facilities, with the affiliate proportion expected to rise.
  • Mariner System Position -- Management described high confidence in “maintain[ing] the level of volume throughput that we are doing today, but that we will actually be able to grow on that.”
  • Regulatory Order Impact (Q4) -- Provided a $56 million one-time positive in NGL, $19 million in Crude, and reduced $14 million in Midstream, plus some carryover rate benefit into 2026; negative $58 million in NGL from hedge timing and $14 million NGL export delay (expected recoup in Q1).
  • 2026 Adjusted EBITDA Guidance -- Narrowed upward to $17.45 billion–$17.85 billion, reflecting USA Compression’s JW Power acquisition.
  • Distribution Growth and Leverage Targets -- Long-term distribution growth targeted at 3%-5% annually; leverage expected within 4.0x–4.5x EBITDA during investment phase.

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RISKS

  • Midstream lost $20 million due to producer shut-ins in the Permian caused by negative Waha pricing.
  • Management noted the NGL transportation and fractionation segment has become the most competitive, with potential overbuild risk in NGL transport, though not explicitly termed a near-term financial headwind.
  • Lake Charles LNG development was formally suspended with no alternate lead-sponsor solution indicated, signaling loss of that near-term project opportunity.
  • Fourth quarter included $60 million in transaction expenses unrelated to the Parkland deal, representing a quarter-specific non-operational cost.

SUMMARY

Energy Transfer (ET +0.19%) delivered record full-year Adjusted EBITDA and achieved significant contract wins across natural gas and NGL segments. The company increased its 2026 Adjusted EBITDA outlook based solely on closing the USA Compression acquisition, while maintaining a robust capital allocation strategy focused on high-return pipeline and terminal expansions. Strategic projects like the large-scale Desert Southwest and Hugh Brinson pipelines are advancing on schedule, enabling the partnership to secure new demand-pull agreements and drive earnings visibility into the next decade.

  • Record NGL exports and growing market share in the Permian and Northeast underpin management’s confidence in further pipeline and fractionation volume growth.
  • Natural gas pipeline and storage systems are expected to benefit from surging demand from power plants and data centers, supported by over 230 Bcf of storage and a multiyear $5.0 billion–$5.5 billion capital plan.
  • Strong long-term contracts, including 20-year arrangements with utility and data center operators, fortify recurring revenue streams and asset utilization rates.
  • Despite suspending development of Lake Charles LNG, Energy Transfer continues to evaluate repurposing strategies for terminal and pipeline assets, highlighting ongoing portfolio optimization.

INDUSTRY GLOSSARY

  • Waha Hub: A critical natural gas pricing and distribution point in West Texas, central to Permian Basin volumetric and price volatility.
  • Fractionation (Frac): The industrial process of separating mixed NGL streams into component products like ethane, propane, and butane.
  • NGL (Natural Gas Liquids): Hydrocarbon products including ethane, propane, and butanes, extracted from natural gas streams for industrial and export markets.
  • Demand-Pull Customer: An end user, such as a utility or data center, that procures transportation capacity to secure fuel supply for operational needs.
  • MLV-2: Refers to Mainline Valve 2 expansion project, as discussed for Dakota Access Pipeline (DAPL) system enhancements.
  • FID (Final Investment Decision): The corporate authorization milestone signifying full commitment to move forward with a capital project based on economics, risk review, and commercial agreements.
  • Backhaul: Pipeline transportation service moving product in the non-primary or reverse flow direction, often utilized to increase asset flexibility and margins.

Full Conference Call Transcript

Thomas E. Long: I am also joined today by Marshall S. McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this morning. As a reminder, our earnings release contains an update to guidance and a thorough MD&A that goes through the segment results in detail. We encourage everyone to look at the release, as well as the slides posted to our website, to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

These statements are based upon our current beliefs, as well as certain assumptions and information currently available to us, and are discussed in more detail in our Form 10-K for the year ended 12/31/2025, which we expect to file later this week. I will also refer to Adjusted EBITDA and Distributable Cash Flow, or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website. Let us start today with financial results. For full year 2025, Adjusted EBITDA was nearly $16,000,000,000 compared to $15,500,000,000 for 2024. This was up 3% over last year and was a partnership record.

DCF attributable to the partners of Energy Transfer LP, as adjusted, was $8,200,000,000 compared to $8,400,000,000 for last year. Operationally, we moved record volumes across each of our interstate, midstream, NGL, and crude segments for the year ended 2025. We also exported a record amount of total NGLs out of our Nederland and Marcus Hook terminals. For the fourth quarter of 2025, we generated Adjusted EBITDA of approximately $4,200,000,000 compared to approximately $3,900,000,000 for the fourth quarter of last year. DCF attributable to the partners of Energy Transfer LP, as adjusted, was approximately $2,000,000,000, consistent with the fourth quarter of 2024.

During the quarter, we recorded records in each of our NGL fractionation throughput, LPG exports, Nederland terminal volumes, and crude transportation throughput. For full year 2025, we spent approximately $4,500,000,000 on organic growth capital, primarily in the NGL and refined products, midstream, and intrastate segments, excluding Sunoco LP and USA Compression from growth capital. Turning to our results by segment for the fourth quarter, and we will start with the NGL and refined products. Adjusted EBITDA was $1,100,000,000, consistent with the fourth quarter of 2024. We saw higher throughput across our Gulf Coast and Mariner East pipe operations, Mont Belvieu fractionators, and Nederland terminal.

Results for the quarter included a one-time $56,000,000 increase from a regulatory order impacting prior and current period rates. These were offset by $58,000,000 of lower gains related to the timing of the settlement of NGL and refined products inventory hedges, which we anticipate will be recognized during 2026. In addition, loading delays related to fog at Nederland resulted in a $14,000,000 impact, which we are on track to make up in 2026. For Midstream, Adjusted EBITDA was $720,000,000 compared to $705,000,000 for the fourth quarter of 2024. This was primarily due to volume growth in the Permian, Northeast, and Ark-La-Tex regions.

Results were partially offset by a one-time expense increase of $14,000,000 in intersegment NGL transportation fees as a result of the previously mentioned regulatory order. For the Crude Oil segment, Adjusted EBITDA was $722,000,000 compared to $760,000,000 for the fourth quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems and our Permian Basin gathering system. Results also included a one-time $19,000,000 increase related to the previously mentioned regulatory order. These were offset by lower transportation revenues, primarily on Bakken Pipeline. In our Interstate Natural Gas segment, Adjusted EBITDA was $523,000,000 compared to $493,000,000 for the fourth quarter of last year.

This increase was primarily due to more capacity sold and higher utilization on several of our pipelines, including Panhandle Eastern, Trunkline, Florida Gas, and Transwestern. In our Intrastate Natural Gas segment, Adjusted EBITDA was $355,000,000 compared to $203,000,000 in the fourth quarter of last year. This increase was primarily due to increased pipeline and storage optimization, as well as increased volumes across our Texas intrastate pipeline system due to third-party volume growth. Now turning to our organic capital guidance. As we previously announced, our 2026 organic growth capital guidance range is projected to be between $5,000,000,000 and $5,500,000,000, excluding Sunoco LP and USA Compression.

We expect approximately two-thirds of this capital to be invested in projects that will enhance our natural gas assets, including the Hugh Brinson and Desert Southwest pipeline projects, Mustang Draw 1 and 2, as well as continued system build-out in the Permian Basin. In addition, approximately a quarter of the growth capital will be in the NGL and refined product segment related to the ongoing construction of the Nederland and Marcus Hook terminal expansions, as well as Frac 9 at Mont Belvieu. These expansions are contracted under long-term commitments and are expected to generate mid-teens returns and considerable earnings growth over the next decade or more.

Beyond these projects, we have a significant backlog of opportunities that are expected to support continued growth. For a closer look at some of our major growth projects, I will start with the natural gas side of our business where we continue to see significant demand for our services.

Operator: In December, we announced that we have upsized the mainline pipeline diameter

Thomas E. Long: for Desert Southwest pipeline project from 42 inches to 48 inches to meet the planned and anticipated customer demand. This will increase the project's capacity to up to 2.3 Bcf per day. A full build-out of the project is expected to cost approximately $5,600,000,000, and we continue to expect the project to be in service by 2029. Our teams continue to actively engage with elected officials, county leadership, and associated communities along the route to communicate project information and updates, and we have engaged with over 275 stakeholders to date.

Our discussions have been very positive, and existing and potential stakeholders are pleased about the economic benefits expected and also realize the critical need for a substantial, reliable supply of gas to help address the significant demand growth in Arizona and New Mexico markets. Next, construction of our Hugh Brinson pipeline is going well. As of today, 100% of the 42-inch pipe has been delivered to our pipe yards, and mainline construction of the pipeline is approximately 75% complete. We expect Phase 1 to be in service in the fourth quarter of this year.

However, if we stay on our current schedule, we should have the ability to flow some early volumes prior to Phase 1 in service, and we continue to expect Phase 2 to be in service in the first quarter of 2027. As a reminder, this system will be bidirectional with the ability to transport approximately 2.2 Bcf per day from west to east and approximately 1 Bcf per day from east to west. The pipe is fully contracted from west to east, and we also have a growing amount of volume committed on backhaul that is expected to add significant upside with no additional capital.

On Florida Gas Transmission, or FGT, we recently completed open seasons for two new projects that are supported by long-term binding agreements from anchor shippers. The Phase IX project, which is designed to expand firm natural gas transportation capacity to multiple new and existing meter stations located across FGT’s market area, will consist of the construction of up to 82 miles of pipeline looping, as well as new and upgraded compression. This would expand FGT’s capacity by up to 550,000,000 cubic feet per day. The project is expected 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.

It will consist of the construction of a new 37-mile lateral to supply the South Florida area, along with compression and a new meter station. The project is expected to be available for service in 2030. Energy Transfer LP’s share of the cost of these two projects is expected to be up to $535,000,000 and $110,000,000, respectively, depending on the final shipper volume elections. Construction of a new storage cavern at our Bethel’s natural gas storage facility, which is expected to double our working gas storage capacity at the facility to over 12 Bcf, remains on schedule to be in service in late 2028.

Now for a brief update around recent natural gas opportunities for new power plant data center development. On our last call, we announced we have long-term agreements with Oracle to deliver approximately 900,000 Mcf per day of natural gas to three U.S. data centers. We recently began flowing gas on the first pipeline lateral to a data center campus near Abilene, Texas. Two more laterals are expected to be completed in mid-2026. Supply for all three of these pipelines will be sourced from our Hugh Brinson and North Texas pipelines.

As a reminder, Energy Transfer LP has entered into a 20-year binding agreement with Entergy Louisiana to provide at least 250,000 MMBtus per day of firm transportation service to fuel their facilities in Richland Parish, Louisiana. Within the last year, we have contracted 6 Bcf per day of pipeline capacity with demand-pull customers. This includes volumes from end users, data centers, and utilities off of Desert Southwest, Hugh Brinson pipelines, and other of our natural gas pipeline systems. We remain in advanced discussions with several other facilities in close proximity to our footprint. Our Oklahoma intrastate power team recently added connections to serve three new power plant loads in the state of Oklahoma totaling approximately 190,000,000 cubic feet per day.

These are expected to come online in 2026. These connections are supported by long-term contracts with investment-grade counterparties. In addition, we have also entered into advanced negotiations to serve another 350,000,000 cubic feet per day of new power plant demand in Oklahoma. Outside of Oklahoma and Texas, our team continues to work on multiple transactions with power plants to provide significant transportation revenue across 13 other states which have a high likelihood of reaching FID. Lastly, construction of eight 10-megawatt natural gas-fired electric generation facilities continues, and we expect our third facility, which will be located at our Gray Wolf processing plant, to be in service in 2026.

The remaining five facilities are expected to be fully constructed and ready for service later this year. Now looking at the Permian processing expansions, we continue to expect our Mustang Draw 1 and 2 plants to be in service in the second quarter and fourth quarter of this year, respectively. At our Nederland terminal, volumes on our Flexport NGL export expansion project have continued to ramp up, and we exported our first two ethylene cargoes in December 2025. This contributed to record exports out of Nederland for 2025. We continue to work with Enbridge on a project to provide capacity for approximately 250,000 barrels per day of light Canadian crude oil through our Dakota Access Pipeline.

We expect to take FID on this project by mid-2026. Turning to Lake Charles LNG. In December, we announced that we suspended the development of this project. As we have previously stated, we continue to be extremely focused on capital, and we have directed our efforts toward our significant backlog of projects we believe provide a more attractive risk-return profile. However, we remain open to discussions with third parties who may have an interest in developing the project, as we would expect to benefit from providing natural gas transportation capacity for the project. We are also exploring other projects to better utilize the terminal in a more profitable way.

Turning to our guidance, we now expect our 2026 Adjusted EBITDA to range between $17,450,000,000 and $17,850,000,000 compared to the previous range of between $17,300,000,000 and $17,700,000,000. This change in guidance is solely attributable to the USA Compression acquisition of JW Power Company, which closed on 01/12/2026. Looking ahead, we are poised for continued growth in 2026 driven largely by the ramp of our Flexport NGL export project, new Permian processing plants, and other projects.

We believe our Hugh Brinson pipeline, which is expected online later this year, is extremely well positioned to become a major U.S. header system that ties together with our network of large-diameter pipelines and allows us the flexibility to deliver natural gas from Texas to the Desert Southwest, Southern Florida, the Midwest, and anywhere in between. In addition to our extensive pipeline systems, we have over 230 Bcf of storage to support the market demands of our customers. This should provide significant upside in the future and further establish Energy Transfer LP’s natural gas pipeline business as the premier option for customers seeking dependable natural gas supply.

We are currently undertaking a large slate of growth projects, including projects that will help address the need for reliable natural gas solutions to support our plant and data center growth plans, as well as the growing international demand for natural gas liquids. As a result, project execution remains one of our top priorities for 2026, and we will continue to place a significant amount of focus on completing projects safely, on time, and on budget. We also continue to see new growth opportunities across all aspects of our business and are extremely well positioned to help meet the substantial growth in demand for energy resources over the next several years.

Given our extensive backlog of potential growth projects, we continue to be extremely focused on capital discipline and will continue to target projects that are expected to generate the highest returns while balancing project risk. We continue to target a long-term annual distribution growth rate of 3% to 5%. We also expect to maintain our leverage target of 4.0x to 4.5x EBITDA during this period of meaningful investment opportunities. In summary, our extensive asset base and diverse product offerings are allowing us to deploy capital across our footprint. With several major growth projects coming online over the next several years, we continue to have great visibility into our ability to grow our franchise for many years to come.

This concludes our prepared remarks. Operator, please open the line for our first question.

Operator: We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. 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. At this time, we will pause momentarily. The first question comes from Theresa Chen with Barclays. Please go ahead. Good morning.

Theresa Chen: It is encouraging to see the continued commercialization momentum across your natural gas asset base. Could you talk about the key drivers behind the progress to date and maybe talk about some of your more creative solutions to address market needs, maybe with, as an example, the multiple legs, service, and revenue opportunities on that system? As you look ahead, where do you see the next set of commercialization or optimization opportunities, whether through new customers or end markets or further integration across your footprint?

Marshall S. McCrea: Hello. This is Mackie. Thanks, Theresa. Yeah, listening to Thomas go through that opening statement, it is hard to not get overly excited. We could not be more excited about the future with our DSW project, a 500-mile, 48-inch pipeline, largest pipeline ever built in the U.S. as far as that distance from the 48. Then you look at our Florida Gas pipeline system with another expansion. Actually, in the open season, we had more interest than even the 550, so we anticipate in the future we will have another expansion off Florida. That is a pipeline that just keeps giving.

Then, as Thomas just spoke about in his opening statements, we have a kind of crown jewel in the middle of our system with Hugh Brinson and

Marshall S. McCrea: able to move a lot of volume from west to east. It also gives us the ability to move volume from east to west, as well as source gas from pretty much any basin in the world to the markets along our system, as well as to the Gulf Coast and into the Southeast. We are very excited about the assets that we have built. As you talked about, or you asked about all the other commercialization, we can go on and on about what Thomas just spoke about. We are building new cryos this next quarter and the fourth quarter out in the Permian Basin, the most prolific basin in the U.S. That flows into our NGL system.

We have an expansion coming on our NGL transportation midyear that feeds into our frac that comes online in the fourth quarter. That feeds onto the Flexport expansion that we just completed in 2025. So just an incredible future for our NGL business in Texas and beyond. We are expanding our Marcus Hook ethane capabilities up there to export. We are by far the largest transporter of NGLs in the Northeast and see continued upside for our partnership. Then you look at all the assets and all the demand around our pipelines. It is not just data centers. What we are chasing is power plants that generate electricity for data centers, for population growth, for manufacturing facilities.

All the power plants that Thomas just talked about and that our team has done such a good job in Oklahoma, to the best of my knowledge, I do not think any of that is data center. It is all just for population growth and new manufacturing growth. We are incredibly excited about our footprint and could not be more elated about where we are going to be over the next ten or fifteen years because of our asset footprint throughout the United States.

Operator: Thank you.

Theresa Chen: And then maybe just a follow-up on the NGL front. Understanding that you have a significant amount of organic growth ahead of you with your infrastructure in flight, just with some of your Permian NGL competitors bringing online downstream assets recently and through the year and moving their own volumes back onto their own system as a result, can you remind us how much third-party downstream Permian volumes you have across your system as a mix of total volumes at this point? How much Y-grade do you transport and frac at this point that does not come from your own processing?

Marshall S. McCrea: Yeah. Maybe Dylan can follow up with the exact percentage, but the majority of our gas, more than half, is coming from our own facilities. We just talked about the two Mustang Draw. Both of those together are 550,000 Mcf a day. That is approaching 85,000 to 90,000 barrels alone just from our own cryos. As we ramp up the rest of our cryos, we have a lot of additional equity-owned liquids that we will be feeding into our massive and first-rate transportation, fractionation, and export business. I do not know the exact percentage.

Dylan A. Bramhall: No, Mackie. You are right on. We are about 60% our own volumes, 40% third party, and that

Dylan A. Bramhall: affiliate volume number continues to grow. We will keep trending that. That 60% will trend up higher as we move through the year.

Theresa Chen: Perfect. Thank you.

Operator: The next question comes from Gabriel Philip Moreen with Mizuho. Please go ahead.

Gabriel Philip Moreen: Hey, good morning, everyone. Wondering if you can maybe touch on, I think last quarter, you talked about converting a pipe from NGL to gas service. Potentially, where that stands? I do not think you may have touched on it in your opening remarks.

Marshall S. McCrea: You bet. This is Mackie again. Let me kind of step back a little bit. Energy Transfer LP has had a strategy since the day we began of looking at every asset we own and asking can we use it in a more profitable, efficient manner. That is an ongoing thing that always happens with us. We have converted a natural gas pipeline to crude oil and are moving Bakken down to the Gulf Coast. We have converted a liquid line to diesel and are moving diesel from the Gulf Coast to the Permian. We have converted a TW line to NGLs, so it is just kind of on and off. That is just a process we go through.

We evaluated that. What we have looked at now, though, is with the growth in the NGLs, both as Dylan just talked about, not only in our systems, but also barrels that we are chasing on third-party systems, we cannot afford to take that out of business. We are going to fill up that NGL pipeline, and if we need to loop another pipeline west to east through Texas, that will be a new project for natural gas.

Gabriel Philip Moreen: Thanks, Mackie. I appreciate that. Then maybe if you can just talk a little bit broadly about how your assets performed during some of the winter weather we have been having and volatility in the gas markets, and also to what extent that may or may not have benefited you financially here in the first quarter?

Marshall S. McCrea: Yeah. You know what? Thomas’s leadership and Greg and Daniel in getting our operations team to not only operate our assets safely, efficiently, and profitably, but we also pride ourselves on times like this when it is critical to move energy to the markets and create, in this case, electricity. In tough times, we proved ourselves during Uri. It paid off in a big way. Same way this last storm that came in January, we were prepared as good as we could be. The negative or positive, however you want to look at it, is that the industry got prepared.

They saw what happens if you have assets that are prepared, they are line-packed, storage, you have people manned out on sills, you can keep gas flowing as much as possible, and you can make a lot of money in those opportunities. With the industry being, I think, much more prepared, all of us got through that better. We did see volumes come off, like they always do, with freeze-off in the Permian Basin. We were able to keep all of our customers whole through our pipeline systems as well as coming out of storage.

We did not see the type of profits and earnings that we saw a number of years ago with Uri, but as we always do, our team performed excellently during that very cold, moderate-day period in Texas and throughout the country.

Gabriel Philip Moreen: Thanks, Mackie.

Operator: The next question comes from Jean Ann Salisbury with Bank of America. Please go ahead.

Theresa Chen: Hi. Good morning. I heard in your comments that there could be some early volumes on Hugh Brinson.

Jeremy Bryan Tonet: I think that with Blackcomb getting pushed to the fourth quarter, there could really be some value to those. Will those volumes go to your third-party customers, or would that kind of all go to Energy Transfer LP? Any sense of how early those could start to ramp?

Marshall S. McCrea: Yeah. This is Mackie again. First of all, let me just say we keep talking about our teams, but we have got one of the best E&C teams, probably the best E&C team in the country, as we build out these assets. We are moving very well ahead of schedule on Hugh Brinson. However, we are going to be real careful. Things can happen. We do not know with certainty when volumes will come on. At this point, we are confident that we will be able to bring on some volumes earlier than the fourth quarter. How we will manage that and how we will operate is how we are contractually and regulatorily allowed to do so.

We are going to do everything we can to get volumes, new egress out of the Permian Basin, because it is much needed for the producers who are suffering from negative pricing out of Waha. It is going to be a huge shot in the arm not only for our assets but also for the Permian Basin. We will see how it plays out. We will be able to talk more by the next earnings call on what we think the volume might be and how early it might be. Right now, we are going to stand by: we are going to have some volumes early in the fourth quarter. We do not know exactly when or how much.

Jeremy Bryan Tonet: That makes sense. Thank you. How do you think about what the limit is for how much Canadian heavy crude could eventually run on the DAPL asset? If Bakken crude production does fall off over the next five to ten years, is there any technical limit to how much the DAPL system could switch over to running Canadian heavy instead?

Dylan A. Bramhall: Sure.

Operator: Hey, Jean Ann. This is Adam. So as we are talking about MLV-2, which I think is what you are referring to, we have

Marshall S. McCrea: definitely done a look. First and foremost, we are going to make sure that we take care of our Bakken producers and make

Adam: sure that they can all move their oil out of that basin. As you mentioned, as we see Bakken volumes steady off and maybe potentially decline in the future, there are a number of different possibilities on moving additional volumes through DAPL. Right now, the project is scoped to move 250,000 barrels a day of light volumes down off the Enbridge mainline system, through DAPL and into Patoka to deliver back to them there. We are definitely looking. I think Enbridge even alluded to it some on their call about additional opportunities down the road as we see Bakken volumes potentially decline.

Jeremy Bryan Tonet: Okay. Thanks. I will leave it there.

Operator: The next question comes from Keith T. Stanley with Wolfe Research. Please go ahead. Hi.

Marshall S. McCrea: Good morning. More of your peers are giving multiyear EBITDA growth expectations.

Operator: How should we think about medium-term growth for Energy Transfer LP, if you would put any framework around that?

Dylan A. Bramhall: Yeah, Keith. Hey, this is Dylan. Let us answer the question this way. When we set our long-term distribution growth rate of 3% to 5% annually, that was very strategically set. That is not meant to be a manufactured growth rate. That is really driven from eating into coverage. When we set that, that basically sets the floor for what we believe we can achieve for our long-term growth rate.

Gabriel Philip Moreen: Got it.

Marshall S. McCrea: That is helpful.

Adam: Second one on

Marshall S. McCrea: you have talked a lot about Texas NGL

Thomas E. Long: recontracting or contract expirations.

Operator: How should we think about recontracting on the Mariner? I think some of those contracts expire in a few years too. Do you see pricing upside there, downside? How is the Mariner system positioned relative to some of the other NGL takeaway options for producers?

Marshall S. McCrea: Excuse me. This is Mackie again. What you just said—oh, what an incredible set of assets we have up there. We built quite a franchise with our Mariner pipelines going west but also the majority of it going east as we speak. As you know, we are expanding our ethane export capabilities out of Marcus Hook. We just see that system as continuing to perform.

I am not going to get into strategies about when contracts fall off and when we are renegotiating and all that, but let us just leave it this way: we are highly confident that not only will we maintain the level of volume throughput that we are doing today, but that we will actually be able to grow on that with some opportunities that we are chasing. It is a great business for us. We will continue to look for ways to expand that business and continue to be the major, dominating player for moving natural gas liquids out of the Marcellus and Utica areas.

Dylan A. Bramhall: Thank you.

Operator: Next question comes from Julien Dumoulin-Smith with Jefferies. Please go ahead. Hey. Good morning, team. Thank you for the time. Appreciate it. Let me just follow up on a couple cleanup items here. On the Desert Southwest project, can you talk a little about the

Marshall S. McCrea: pro forma economics? Moving to 48, good stuff, but

Operator: how are you thinking about just setting the expectations on economics there? Going back to Jean Ann’s question

Marshall S. McCrea: from a moment ago, looking at the DAPL side, can you talk about maybe some of the tariffs and how you are thinking about that, maybe relative to what you saw in the last decade on tariffs, to give a little bit of preliminary sense of what pro forma economics might look like for the 250,000 or more, as it may be, that you are looking at there?

Marshall S. McCrea: You bet. This is Mackie. I will take the Desert Southwest, and then Adam can follow up on the DAPL question. I will say it again, and I just keep thinking about, as Thomas read that out, how excited I am and we are—the executive team—about what we have built and the incredible position we are in the country. Certainly, moving more gas toward Phoenix is a big deal. If you talk to some of those larger players out there, they are talking about anywhere between 25 and 35 gigawatts of growth above what is needed today. That is a lot more gas than our 48-inch can transport.

Talking about returns, I would say this: we do not want to overexaggerate expectations, but right now, that type of project that is sized—you know, everything comes in the distance and diameter and throughput—we think that will be probably one of the better rate-of-return projects that we have ever built as far as a one-way flow. We always mention Hugh Brinson. It is going to generate money in multiple directions, but going from east to west, to New Mexico, providing new natural gas supplies for markets along southern New Mexico and then into the fast-growing population—probably data centers, etc.—in Phoenix, that is going to be one of the better projects that we have built in a long time.

Adam: Hey, Julien. This is Adam. We just closed on our no-open season on DAPL, and we are really happy with the result. We were able to actually add some incremental volume, but not only add incremental volume, get some of our base customers extended out well beyond the mid-2030s. We did that at rates that were what we believe are good market rates reflective of the value of the assets. As we tie the MLV-2 conversation in with that, we expect those rates to be in line with the rates that we are seeing from the Bakken producers in the basin.

Operator: Yeah, I hear it. Hey, Mackie, just super quick on that expansion and further upsize on DSW. It looks like even next year, we could get some real clarity on the 25-plus that you alluded to a second ago. The scope seems

Marshall S. McCrea: pretty real-time that we are going to get that expansion in capacity through the IRP processes. Do you think we could be talking about a further expansion of DSW in some form or fashion here

Operator: in even the next 12 months? I know you guys just did it here, but

Thomas E. Long: not being facetious.

Marshall S. McCrea: We love your thinking. If there is an opportunity to build more pipe, we certainly will do that. I would think about it this way: we own Florida Gas Transmission. We continue to loop that pipeline. We have got gas coming into Florida Gas on the east, moving back into Texas. We have got gas coming to Louisiana, moving back to Texas, and I can go on and on. We have multiple pipelines in those ditches. We are adding our Phase IX and very likely will add Phase X at some point in the future. Do we see Desert Southwest being a similar opportunity? Absolutely.

As New Mexico grows and as the Phoenix area grows with demand for natural gas for a number of reasons, there are certainly going to be opportunities to loop, add compression, and backhaul. Who knows what the future holds? We certainly will look forward to any of those opportunities on adding additional assets to deliver gas to those markets. Awesome. Thanks, guys. All the best. Talk soon. See you soon. Thank you. The next quest

Operator: The next question comes from John Ross Mackay with Goldman Sachs. Please go ahead.

Marshall S. McCrea: Hey, good morning, guys. Thank you for the time. Why do we not stay on DSW? You guys upsized, but you

Operator: kept your timeline intact.

Gabriel Philip Moreen: Can you just remind us when you need to make a call on sizing? Then, in terms of executing toward coming online at the end of the decade, what are the key milestones you want us to watch from our side of the execute?

Marshall S. McCrea: I will say once again, the E&C team is so good. On all these projects, we try to look ahead, and in the marketplace today you can really get caught off guard if you do not order steel when you price it to your customers. You do not order compression, both from not only a pricing standpoint but also a delivery standpoint. Mike Morgan and his team did a great job working with Beth on the timing, so we got way ahead of that. We actually secured 42-inch with the option to go to 48-inch. In December, we exercised that option. That is officially, of course, upsized to a 48-inch.

We have already ordered all of that pipe, and we have already ordered all the compression to move the full 2.3 Bcf a day.

Operator: Then, sorry, just in terms of construction timing,

Gabriel Philip Moreen: the permits, etc.?

Marshall S. McCrea: Yes. We are ahead of schedule. We have customers out there that want weekly and monthly updates, so we do this very rigorously. As we have said, we have already contacted local, state, and federal constituents all along the way. We have a substantial amount of the right-of-way already surveyed or permission to survey. As we have said before, much of this falls in the existing corridor of pipelines and utilities, so it is in a really good area where we are laying this. Right now, worst case, we will be in by 2029, and we will see if we can do any better, like we do on some of our other projects. Everything is going as planned. Okay.

Then just a quick second one for me.

Operator: Lake Charles,

Gabriel Philip Moreen: you mentioned you have a couple different options there now that you have suspended your specific project. Can you just walk us through what that could end up looking like?

Marshall S. McCrea: As we said earlier, our strategy at Energy Transfer LP is looking at all of our assets, not just our pipeline assets and repurposing those, but also our terminals. At Lake Charles, it looks like it is certainly not going to move forward with us being the lead. Whether or not somebody else steps in and looks to build a pipeline on our terminal, we will see. In the meantime, we are looking at—there is no limit to what we are looking at. It could be NGLs. It could be a crude oil terminal. It could accommodate other commodities.

We will see how it plays out, but certainly, as I said, we look at all of our assets, and that is such a great location. It has a really good draft and a really good terminal, and we do expect it to create some kind of business going forward in that terminal.

Operator: Okay. Thanks for the time. The next question. The next question comes from Manav Gupta with UBS. Please go ahead.

Marshall S. McCrea: Good morning.

Manav Gupta: You guys are obviously leading from the front when it comes to signing up with data centers. There is a lot of focus on pipe, and you have some of the best. I wanted to focus a little bit on the storage opportunities. These data centers require what is called the “five nines,” in terms of 99.999% utilization. Can you talk a little bit about how Energy Transfer LP can benefit from the multiple storage opportunities that will arise as you try and build out these data centers along with the pipes you are building for them?

Marshall S. McCrea: You bet. I will give accolades to Adam, who is sitting next to me, and his team and what they have done in Texas and a few other states, and then Beth and what her team are doing in the other areas around data centers. There are even some producers and others that are looking to provide gas to data centers, but nobody can really do it unless you own big-diameter pipe and unless you can come out of storage. We have done a great job in what has been public and other opportunities that we are working on to provide firm transportation through our big-inch pipelines throughout the country.

Then, as we mentioned earlier, we have over 230 Bcf of storage and are expanding on that as we speak to be able to provide the much—100% reliability that is required by these data centers.

Manav Gupta: Perfect. My quick follow-up is you mentioned, obviously, Oracle. Obviously, you are dealing with Entergy, and both those companies are indicating a much stronger demand. I am trying to understand if they decide to upsize their orders and want significantly more gas from you, would you be in a position to supply them with a lot more gas than what you have currently signed them on for?

Marshall S. McCrea: This is Mackie again. Absolutely. Wherever there is a need for natural gas supply, there is no company in the country anywhere close to the capability with the footprint that we have. In fact, our data team put together a map showing all the fiber optic systems that run through the country and then we also have the electric transmission system. It is ironic how you can almost lay our pipelines along many of those corridors. We are extremely well positioned with our big-inch, gigantic 42-inch pipeline systems throughout the country, but especially Texas and some of the other states like Louisiana. Nobody is better positioned.

Yes, we can upsize, loop, add compression, and provide whatever natural gas needs that anybody has along our system.

Manav Gupta: Thank you so much.

Operator: The next question comes from Michael Jacob Blum with Wells Fargo. Please go ahead.

Gabriel Philip Moreen: Wanted to ask on Waha. Pricing has been, as you know, very volatile lately—negative in Q4, spiked in Q1 with the storm. Can you just remind us how much open capacity you have to capture spreads there? I know you have also

Michael Jacob Blum: firmed up a bunch of that lately.

Marshall S. McCrea: Unfortunately or fortunately, we have firmed up a lot of that lately. That is what helped us get Hugh Brinson and other projects done. That is just the nature of the business. We still have about 160,000 Mcf a day that we are benefiting from wherever the spread is from a day-to-day basis. We are pretty excited about Hugh Brinson coming on and really opening up the basin for everybody and really benefiting the producers.

Thomas E. Long: Got it.

Gabriel Philip Moreen: Thanks for that. Then

Michael Jacob Blum: you and your competitors are all expanding frac capacity at Belvieu. I am curious if you are seeing any change in rates for fractionation with all this new capacity anticipated to enter the market. Thanks.

Marshall S. McCrea: Probably of all the segments we have, the NGL transportation and fractionation segment has become the most competitive. There tends to be an overbuild, heading toward an overbuild a little bit, in the NGL transport. Not sure on the frac. Once again, we always answer questions like this in that we really do not say we do not care, but we do not worry about what our competitors are building. Our jobs are to build assets, build them up, and keep them full for as long as possible, and we feel real good about filling up our natural gas transportation and then ramping up our Frac 9 as we bring it online at the end of this year.

Jeremy Bryan Tonet: Thanks, Mackie.

Operator: The next question comes from Alvaro Scotto with RBC Capital Markets. Please go ahead.

Theresa Chen: Hey. Good morning. Good morning, everyone. Thanks for taking my question. With the new growth projects that you announced and this big opportunity set that you see ahead,

Jeremy Bryan Tonet: where do you think

Theresa Chen: kind of annual growth CapEx could shake out over the next few years?

Gabriel Philip Moreen: Yeah. This

Thomas E. Long: Alvaro, thanks for that.

Michael Jacob Blum: Obviously,

Thomas E. Long: when you look out

Dylan A. Bramhall: and you

Thomas E. Long: go over all these projects that we have been talking about, there is a whole lot more of them in the queue here, actually, that we are looking at. It is hard. We do not generally give growth guidance like that, but you can see that we came out early with the $5,000,000,000 to $5,500,000,000. With everything we are talking about, we feel like it is going to stay pretty strong. It is probably a little bit early to give that guidance, but it is clearly a lot of good projects that we have to look at. I do not know, Dylan, if you want to

Marshall S. McCrea: add a little bit more to that.

Dylan A. Bramhall: Sure. As we look out, one thing to remember is when we talk about our growth capital, the growth capital guidance that we put out for this year, we are not as concerned about cash flow and staying within cash flow there. When we look at long term, where we really govern this is staying within leverage targets. As you look out, we have strong growth coming on from a lot of assets going in service over the next couple of years, and that definitely creates more debt capacity for us.

We are really set up well to be able to fund whatever Mackie and the team put together over the next few years in this great opportunity set that we have in front of us.

Theresa Chen: Great. Thanks. Then just one quick follow-up on the project with Enbridge. What is it going to take to get to FID? What else is required at this point?

Adam: I will let Enbridge comment on what is required on their side. From our perspective, we are ready. We have the design systems in place. There is a little bit of work we need to do, obviously, to make this work, but we are in the commercialization phase, continuing to have productive discussions with customers in Canada.

Jeremy Bryan Tonet: Great. Thank you very much.

Operator: The next question comes from Zackery Van Everen with TPH. Please go ahead.

Gabriel Philip Moreen: Hi, all. Thanks for taking my question. Maybe starting on the Oracle

Operator: data center, can you talk to how much gas is flowing today and what the capacity is on those legacy pipelines before Hugh Brinson gets online?

Marshall S. McCrea: This is Mackie again. That is kind of confidential. We are not going to really share a lot of that exact volume flow at this time, but we are connected to our North Texas pipeline. We will be connected to Hugh Brinson in the Abilene area by about the middle of the year. We are well positioned to be able to provide whatever gas supplies that they will need as they build out their data center.

Dylan A. Bramhall: Got it. Makes sense. Then one more on

Gabriel Philip Moreen: Hugh Brinson. You talked to more and more backhaul contracts coming online or getting signed.

Operator: What, in your eyes,

Marshall S. McCrea: or what amount of gas do you think will actually make it to Carthage, if any? Or do you think most of that will be absorbed in the Dallas, kind of Abilene, area?

Manav Gupta: Gosh.

Marshall S. McCrea: If we had that crystal ball, we would certainly think differently about different pipes and stuff, but who knows? As we think about it, there is going to be 10 or 11 Bcf of new pipeline capacity built out of the Permian.

Thomas E. Long: There is

Marshall S. McCrea: several 48-inch pipes and 42-inch pipes being built out of Katy over into Louisiana. We have got a bunch of pipes in North Louisiana heading south, and we have a ton of pipes with capacity. Who knows where the pinch points will be? The message from us is this: there is nobody that can predict and answer that question—where is most of the gas going to be, where is the least? What we can do is take the least-price gas and transport it to the market that is most needed in most areas of the United States.

We love the position we are in, and we will be able to capitalize on whatever dynamics happen on the production front and ebbs and flows from the Permian Basin to East Texas to Haynesville. We just love the position we are in, not knowing exactly where all this is headed.

Manav Gupta: Got it.

Dylan A. Bramhall: Appreciate the time. Thanks.

Operator: The next question comes from Michael Blum with TD Cowen. Please go ahead.

Michael Jacob Blum: Yes, morning. Thanks for taking my question. You have mentioned potential to FID, or a high likelihood of FID-ing, projects across 13 states related to power.

Operator: That obviously sounds like a high number on the surface, so I am wondering if you could give us a flavor of what those projects look like—if they are more like Cloudburst

Marshall S. McCrea: or the Oracle-type projects—and if that number has grown since the prior call.

Marshall S. McCrea: This is Mackie, and Adam may want to follow up on this. He is closer to a lot of this. Once again, I will give accolades to our data center teams, one led by Adam and one led by Beth. We are chasing every opportunity to provide gas for natural gas-fired generation for data centers. We are well positioned with all of our pipelines. As we mentioned, we are talking to 150-plus different opportunities, and it seems like a new one or two come in every day. We have some deals that we have already done where there are some options data centers can exercise and take some capacity on us.

It is across the board of the opportunities that we are chasing and negotiating. We have been very successful so far. Because of our team and because of our assets, we expect to do a whole lot more deals tied to electric generation behind data centers.

Adam: I would just add that in terms of project scope, they really range in size and go anywhere from the new, longer-haul, new pipelines to just interconnects that are, like Mackie mentioned earlier, sitting right on top of our system where we are at these crossroads of transmission fiber and our assets and are simply installing a new interconnect. The scope really varies from simple interconnects to bigger pipeline projects. Got it. Great. My follow-up is more specific

Operator: to the quarterly results. In the press release, there was mention of this regulatory order impacting prior period and current period rates.

Marshall S. McCrea: So

Operator: I am wondering if you could provide a little more detail on what specifically that referred to and what that means for the increase in earnings moving forward, because it seemed like there was a net benefit on the quarter and should provide a

Thomas E. Long: modest uplift to future earnings.

Gabriel Philip Moreen: Thanks. Sure.

Adam: This is Adam again. I will hand it over to Dylan for the second half of your question on the looking forward. To start, let us just say we are extremely happy with the appointment of Chairman Sweat and the actions that the FERC under her leadership have taken so far. As far as the index issue specifically, in 2022 FERC took what was ultimately determined to be an unlawful action in changing the index methodology. Last year, this FERC issued an order allowing pipelines to recover those lost revenues. That is what those one-timers reflect, and Dylan can chime in on what it looks like going forward.

Dylan A. Bramhall: Yeah, Jason. I will walk you through real quickly here or wrap up on the quarter and the one-time impacts so we can help you get a clean quarter to see how things are going to look going forward. On the NGL segment, we had $56,000,000 from this regulatory order that was a one-time positive. You get a little carryover effect from where that sets the rates now, but that is primarily one-time there. We also had a negative $58,000,000 on the timing of the hedge gains around our hedged NGL inventory and a $14,000,000 impact from the fog at Nederland. Both of those, that $72,000,000 total, we expect to recoup in the first quarter.

That is a big boost moving into 2026 there. That is a net negative $16,000,000 on NGL. Crude picked up $19,000,000 one-time from the regulatory order. Midstream lost $14,000,000 from transport fees that it pays on that regulatory order. It also had about $20,000,000 from producer shut-ins in the Permian where we saw shut-in gas due to low—really negative—pricing in Waha, for negative $34,000,000 total net at Midstream. The big one was $60,000,000 in transaction expenses unrelated to closing of the Parkland transaction. If you put this all together to clean up the quarter, you have got a net negative about $90,000,000 for that fourth quarter that you would want to add back to get a clean quarter.

Like you said, you have got $70,000,000-plus that we expect to recoup about in the first quarter.

Marshall S. McCrea: Great. That is super helpful. Thank you.

Operator: This concludes our question and answer session. I would like to turn the conference back over to Thomas E. Long for any closing remarks.

Jeremy Bryan Tonet: Yes. Once again, thank

Thomas E. Long: all of you for joining us today, but also a lot of appreciation for some very good questions, very good dialogue, and discussion on this. As you can see,

Marshall S. McCrea: we have got a

Thomas E. Long: lot of great things to talk about with these projects,

Marshall S. McCrea: not just for

Thomas E. Long: 2026, but for a long time into the future, like Mackie was mentioning. Thank all of you. We look forward to all your follow-up questions.

Marshall S. McCrea: Please get a hold of our IR team, and we are happy to jump on a call with you again. Thanks so much.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.