Energy Transfer Fourth Quarter 2025 Earnings Call - Pipeline buildout and project ramp drive upgraded EBITDA guidance and heavy capex discipline

Tom Long, Executive (likely CEO or CFO), Energy Transfer: Thank you, operator, and good morning, everyone, and welcome to the Energy Transfer fourth quarter 2025 earnings call. I’m also joined today by Mackie 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, and 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 details in our Form 10-K for the year ended December 31, 2025, which we expect to file later this week. I’ll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You’ll find a reconciliation of our non-GAAP measures on our website. Let’s start today with financial results for full year 2025. Adjusted EBITDA was nearly $16 billion compared to $15.5 billion for 2024. This was up 3% over last year and was a partnership record. DCF, attributable to the partners of Energy Transfer, as adjusted, was $8.2 billion compared to $8.4 billion 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 $4.2 billion, compared to approximately $3.9 billion for the fourth quarter of last year. DCF, attributable to the partners of Energy Transfer, as suggested, was approximately $2 billion, 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 $4.5 billion on organic growth capital, primarily in the NGL and refined products, midstream, and intrastate segments, excluding Sun and USA Compression CapEx. Turning to our results by segment for the fourth quarter, and we’ll start with the NGL and refined products. Adjusted EBITDA was $1.1 billion, consistent with the fourth quarter of 2024. We saw higher throughput across our Gulf Coast and Mariner East pipeline operations, Mont Belvieu Fractionators, and Nederland Terminal. Results for the quarter, including a one-time $56 million increase from a regulatory order impacting prior and current period rates. These were offset by $58 million of lower gains related to the timing of the settlement of NGL and refined products inventory hedges, which we anticipate will be recognized during the first quarter of 2026.

In addition, loading delays related to fog at Nederland resulted in a $14 million impact, which we are on track to make up in the first quarter of 2026. For midstream, Adjusted EBITDA was $720 million, compared to $705 million 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 million in intersegment NGL transportation fees as a result of the previously mentioned regulatory order. For the crude oil segment, Adjusted EBITDA was $722 million, compared to $760 million 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 million increase related to the previously mentioned regulatory order. These were offset by lower transportation revenues, primarily on the Bakken Pipeline. In our interstate natural gas segment, Adjusted EBITDA was $523 million, compared to $493 million 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. And for our intrastate natural gas segment, Adjusted EBITDA was $355 million, compared to $263 million 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 and $5.5 billion, excluding Sun 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 products segment related to the ongoing construction of the Nederland and Marcus Hook terminal expansions, as well as Frac IX and Mont Belvieu. These expansions are contracted under long-term commitments and are expected to generate mid-teen 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’ll start with the natural gas side of our business, where we continue to see significant demand for our services. In December, we announced that we have upsized the mainline pipeline diameter 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 $5.6 billion, and we continue to expect the project to be in service by the fourth quarter of 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 market. 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 one 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 one in service. We continue to expect phase two 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 Nine project, which is designed to expand firm natural gas transportation capacity to multiple new and existing meter stations located across FGT’s market area. This project 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 million 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 the first quarter of 2030.

Energy Transfer’s share of the cost of these two projects is expected to be up to $535 million and $110 million, respectively, depending on the final shipper volume elections. Construction of a new storage cavern at our Bethel 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 and 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 has entered into a 20-year binding agreement with Entergy Louisiana to provide at least 250,000 MMBtu per day of firm transportation service to fuel their facilities in Richland Parish, Louisiana. Within the last year, we have contracted over 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 million cubic feet per day. These are expected to come online in the second quarter of 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 million 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 8-10 MW natural gas-fired electric generation facility continues, and we expect our third facility, which will be located at our Gray Wolf processing plant, to be in service in the first quarter of 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 Flex Port NGL export expansion project have continued to ramp up, and we exported our first 2 ethylene cargoes in December 2025. This contributed to record exports out of Nederland for the fourth quarter of 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, and 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 discipline, and we have directed our efforts toward our significant backlog of projects that 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’re 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 $17.45 billion-$17.85 billion, compared to the previous range of between $17.3 billion-$17.7 billion. This change in guidance is solely attributable to the USA Compression’s acquisition of JW Power Company, which closed on January 12, 2026. Looking ahead, we are poised for continued growth in 2026, driven largely by the ramp of our Flex Port 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, South 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’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 power 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 and 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%-5%. We also expect to maintain our leverage target of 4-4.5 times EBITDA during this period of meaningful investment opportunities. In summary, our extensive asset base and diverse product offerings is 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 up for our first question.

Dylan, Financial Executive, Energy Transfer2: 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’re 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 to assemble our roster. The first question comes from Theresa Chen with Barclays. Please go ahead.

Dylan, Financial Executive, Energy Transfer3: Good morning. It’s encouraging to see the continued commercialization momentum across your natural gas asset base. Could you talk about the key drivers behind the progress today, and maybe talk about some of your more creative solutions to address market needs? Maybe with Hubrenton as an example, in the multiple legs of 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?

Mackie McCrea, Executive, Energy Transfer: Hello, this is Mackie. Thanks, Teresa. You know, listening to Tom go through that opening statement, it’s hard to not get overly excited. So, we couldn’t 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 with the 48. And 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’ll have another expansion off Florida. That’s a pipeline that just keeps giving.

And then, as Tom just spoke about in his opening statements, we’ve got kind of crown jewel in the middle of our system with Hugoton, able to move a lot of volume from west to east, but it also give 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 to the Southeast. So we’re very excited about the assets that we have built. As you talked about, or you asked about all the other commercialization, and, you know, we can go on and on about what Tom just spoke about. We’re 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, mid-year. That feeds into our Frac that comes online in the fourth quarter. That feeds onto the Flex Port expansion that we just completed in 2025. So just an incredible, future for the, our NGL business in Texas and beyond. We’re expanding our Marcus Hook, ethane, capabilities up there to export. We’re by far the largest transporter of NGLs in the Northeast, and con-- and CPAS continue to upside for our partnership. And then you look at, all the assets and all the demand around our pipelines. It’s not just data centers.

What we’re chasing is power plants that generate electricity for data centers, for population growth, for manufacturing facilities, all the power plants that Tom just talked about, and that our team has done such a good job in Oklahoma. To the best of my knowledge, I don’t think any of that’s data centers. It’s all just for population growth and new manufacturing growth. So we are incredibly excited about our footprint and couldn’t be more elated of where we’re gonna be over the next 10 or 15 years because of our asset footprint throughout the United States.

Dylan, Financial Executive, Energy Transfer3: Thank you. 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 systems as a result, can you remind us how much third-party downstream Permian wide grade volumes you have across your system as a mix of total volumes at this point? How much wide grade do you transport and frac at this point that doesn’t come from your own processing?

Mackie McCrea, Executive, Energy Transfer: Yeah, maybe Dylan can follow up with this 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’s approaching 85,000-90,000 barrels alone, just from our own cryos. And as we ramp up the rest of our cryos, we’ve got a lot of additional equity-owned liquids that we will be feeding into our massive infrastructure, transportation, fractionation and export business. I don’t know the exact percentage.

Dylan, Financial Executive, Energy Transfer: No, Mackie, you got it right on. We’re about 60% our own volumes, 40% third party, and that affiliate volume number continues to grow. So you know, we’ll keep trending that. That 60% will trend up higher as we move through the year.

Dylan, Financial Executive, Energy Transfer3: Perfect. Thank you.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Gabe Moreen with Mizuho. Please go ahead.

Speaker 3: Hey, good morning, everyone. Wondering if you could maybe touch on, I think last quarter you talked about converting a pipe from NGL to gas service, potentially where that stands. I don’t think you may have touched on it in your opening remarks.

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

What we’ve looked at now, though, is with the growth in the NGLs, both as Dylan just talked about, not only on our systems, but also barrels that we’re chasing on third-party systems, we can’t afford to take that out of business. We’re gonna 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.

Matthew, Executive, Energy Transfer: ... Thanks, Matthew, I appreciate that. And then maybe if you can just talk a little bit broadly about how your assets performed during some of the winter weather we’ve been having and the volatility in the gas markets, and also to what extent that may or may not have benefited you guys financially here in the first quarter?

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

They saw what happens if you have assets that are prepared, they’re line pack, storage, you got people manned out on your facilities, you can keep gas flowing as much as possible, and you can make a lot of money in those opportunities. So 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-offs 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. So yep, we didn’t 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 7 or 8-day period in Texas and throughout the country.

Matthew, Executive, Energy Transfer: Thanks, Matt.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Jean Ann Salisbury with Bank of America. Please go ahead.

Speaker 5: Hi, good morning. I heard in your comments that there could be some early volumes on Hugh Brinson. I think that with Blackhawk 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 ET? And any sense of how early those could start to ramp?

Mackie McCrea, Executive, Energy Transfer: Yeah, this is Matthew again. First of all, let me just say, we keep talking about our teams, but we’ve got one of the best E&C teams, if not the best E&C team in the country, as we build out these assets. And so, we are moving very well ahead of schedule on Hugh Brinson. However, we’re gonna be real careful. Things can happen. We don’t 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. And how we’ll manage that and how we’ll operate is how we contractually and regulatory are allowed to do so.

But we’re gonna do everything we can to get volumes, new egress out of the Permian Basin because it’s much needed for the producers who are, you know, working, you know, who are suffering from negative pricing out of the Waha. And so it’s gonna be a huge shot in the arm, not only for our assets, but also for the Permian Basin. So we’ll see how it plays out. We’ll be able to talk more about the next earnings call on, on kind of what we think the volume might be and how early it might be, but right now we’re gonna stand by. We’re gonna have some volumes early in the fourth quarter. We don’t know exactly when or how much.

Speaker 5: That makes sense. Thank you. And 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 5-10 years, is there any technical limit to how much the DAPL system could switch over to running Canadian heavy instead?

Adam, Executive, Energy Transfer: Sure. Hey, Jean Ann, this is Adam. So as we’re talking about MLO2, which I, I think is what you’re referring to, we’ve definitely done a look. First and foremost, we’re gonna make sure that we take care of our Bakken producers and make sure that they can all move their oil out of that basin. But as you mentioned, as we see Bakken volumes kind of steady off and maybe potentially decline in the future, there’s a number of different possibilities on moving additional volumes through DAPL. Right now, the project’s scoped to move 250,000 barrels a day of light volumes down, kind of off the Enbridge mainline system, through DAPL and into Patoka to deliver back to them there.

But we’re definitely looking, and I think Enbridge even alluded to it some on their call about additional opportunities, down the road as we see, Bakken volumes potentially decline.

Speaker 5: Okay, thanks. I’ll leave it there.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Keith Stanley with Wolfe Research. Please go ahead.

Matthew, Executive, Energy Transfer: Hi, good morning. More of your peers are giving multi-year EBITDA growth expectations. How should we think about medium-term growth for Energy Transfer, if you’d put any framework around that?

Dylan, Financial Executive, Energy Transfer: Yeah, Keith, hey, this is Dylan. Let us answer the question this way. When we set our long-term distribution growth rate of 3%-5% annually, that was very strategically set. That’s not meant to be a manufactured growth rate that’s 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.

Matthew, Executive, Energy Transfer: Got it. That, that’s helpful. Second one on—so you’ve talked a lot about Texas NGL recontracting or, or contract expirations. How should we think about recontracting on the Mariner system? I think some of those contracts expire in a few years, too. So do you see pricing upside there, downside? And how is the Mariner system positioned relative to some of the other NGL takeaway options for producers?

Mackie McCrea, Executive, Energy Transfer: Excuse me, this is Matthew again. Yeah, what a, excuse me a second. What an incredible, incredible set of assets we have up there. We built quite a franchise with our Mariner pipelines going west, but also majority of it going east. As we speak, and as you know, we’re expanding our ethane export capabilities out of Marcus Hook. We just see that system as continuing to perform. We’re not gonna get into strategies about when contracts fall off and when we’d be renegotiating all that, but let’s just leave it this way: we are highly confident that not only will we maintain the level of volume throughput that we’re doing today, but that we’ll actually be able to grow on that with some opportunities that we’re chasing. So it’s a great business for us.

We’ll continue to look at ways to expand that business and continue to be the major dominating player for moving natural gas liquids out of the Marcellus Utica areas.

Speaker 7: Thank you.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Julian Dumoulin-Smith with Jefferies. Please go ahead.

Speaker 7: Hey, good morning, team. Thank you guys for the time. Appreciate it. Let me, let me just, follow up on a couple, couple, cleanup items here. On, on the Desert Southwest project, can you talk a little about the, the pro forma economics? I mean, obviously, moving to 48, good stuff, but, how are you thinking about just setting the expectations on, on economics there? And then going back to Jean Ann’s question from a moment ago, looking at the, the DAPL side, can you talk about maybe some of the tariffs and how you think about that, maybe relative to what you saw, you know, 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 or, or more, maybe, that you’re looking at there?

Mackie McCrea, Executive, Energy Transfer: You bet. This is Matt. I’ll answer the Desert Southwest, and then Adam can follow up on the DAPL question. But we’ll say it again, and I just keep thinking about, as Tom read that, how excited I am, and we are, the executive team, about what we’ve built and the incredible position we’re in, in the country, and certainly moving more gas toward Phoenix is a big deal. If you talk to some of those larger players out there, they’re talking about anywhere between 25 and 35 gigawatts of growth above what’s needed today. That’s a lot more gas than our 48-inch can transport.

But talking about returns, I guess I’d say this: We don’t wanna over-exaggerate the expectations, but right now, that type of project, that size, you know, everything coming into distance and diameter and throughput, we think that’ll be probably one of the better rate of return projects that we’ve ever built just as far as a one-way flow. We always, we always mention Hugh Brinson, it’s gonna generate money in multiple directions, but going from east to west through New Mexico, providing new natural gas supplies for markets along southern New Mexico and then into the just fast-growing population, probably data centers, et cetera, et cetera, in Phoenix, that’s gonna be one of the better projects that we’ve built in a long time.

Adam, Executive, Energy Transfer: Hey, Julian, this is Adam. So we just closed on an open season on DAPL, and we’re 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, you know, well beyond kind of the 20, mid-2030s. And, you know, we did that at rates that were good, what we believe, good market rates reflective of the value of the assets. And so as we kind of tie the MLO2 conversation in with that, we expect those rates to be in line with the rates that we’re seeing from the Bakken producers in the basin.

Speaker 7: Yeah, I hear you. Hey, Matthew, just quick, super quick, on that expansion and further upside on DSW. I mean, it looks like even next year, we could get some real clarity on the 25+ that you alluded to a second ago. I mean, the scope seems pretty real-time that we’re gonna get that expansion and capacity through the IRP processes. You think we could be talking about a further expansion of DSW in some form or fashion here in even the next 12 months? I know you guys just did it here, but not being suspicious.

Mackie McCrea, Executive, Energy Transfer: Yeah, we love your thinking. If there’s an opportunity to build more pipe, we certainly will do that. I guess I would think about it this way: We own Florida Gas Transmission. We continue to loop that pipeline. We’ve got gas coming into Florida Gas on the east, moving back into Texas. We’ve got gas coming to Louisiana, moving back to Texas, and I can go on and on, but we have multiple pipelines in those ditches. We’re adding our Phase Nine, very likely we’ll add Phase Ten at some point in the future. Do we see Desert Southwest being of similar opportunities? Absolutely. As New Mexico grows and as Phoenix area grows with demand for natural gas for, you know, a number of reasons, there’s certainly gonna be opportunities to loop, add compression, backhaul.

Who knows what the future holds, but we certainly will look forward to any of those opportunities on adding additional assets to deliver gas to those markets.

Speaker 7: Awesome. Thanks, guys. All the best. Talk soon. See you soon.

Mackie McCrea, Executive, Energy Transfer: Thank you.

Dylan, Financial Executive, Energy Transfer2: The next question comes from John McKay with Goldman Sachs. Please go ahead.

Speaker 6: Hey, good morning, guys. Thank you for the time. Why don’t we stay on DSW? You guys upsized, but you know, kept your timeline intact. Can you just remind us, you know, when do you kind of need to make a call on sizing? And then just in terms of executing towards coming online end of the decade, what are the key kind of milestones you want us to watch from our side of the execute?

Mackie McCrea, Executive, Energy Transfer: Yeah, I’ll say it once again, our 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 don’t order steel when you price it to your customers, you don’t 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 the first part of December. We exercised that option, so that is officially, of course, upsized to a 48-inch. We’ve already ordered all of that pipe, and we’ve already ordered all the compression to move the full 2.3 Bcf/d.

Speaker 6: ... sorry, just in terms of construction timing, the permits, et cetera?

Mackie McCrea, Executive, Energy Transfer: 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’ve said, we’ve already contacted both 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’ve said before, much of this falls in an existing corridor of pipelines and utilities, so it’s in a really good area where we’re laying this to, and we’re, you know, right now, worst case, we’ll be in by the fourth quarter of 2029, and we’ll see if we can do any better like we do on some of our other projects. But everything’s going as planned.

Speaker 6: Okay. And just a quick second one for me. Lake Charles, you mentioned, you have mentioned kind of a couple different options there now that you’ve kind of suspended your specific project. Can you just walk us through what, what that could end up looking like?

Mackie McCrea, Executive, Energy Transfer: Yeah, as we said earlier, as a strategy, Energy Transfer, we’re looking at all of our assets, not just our pipeline assets and repurposing those, but it’s also our terminals. And so at Lake Charles, it looks like it’s 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’ll see. But in the meantime, we’re looking at. There’s no limit to what we’re looking at. We’re looking at, it could be NGLs, it could be a crude oil terminal, it could be accommodate other commodities. So we’ll 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 out of that terminal.

Speaker 6: Okay. Thank you for the time.

Mackie McCrea, Executive, Energy Transfer: You-

Dylan, Financial Executive, Energy Transfer2: The next question, the next question comes from Manav Gupta with UBS. Please go ahead.

Dylan, Financial Executive, Energy Transfer0: Good morning. You guys are obviously leading from the front when it comes to signing up for data centers. There’s 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, like, the five-nine, you know, in terms of 99.99% utilization. So, can you talk a little bit about how ET can, you know, benefit from the multiple storage opportunities that will arise as you try and build out these data centers along with the pipes you’re building for them?

Mackie McCrea, Executive, Energy Transfer: You bet. Now, I’ll give accolades to Adam, who’s sitting next to me, and his team and what they’ve done in Texas and a few other states, and then Beth and what his her team are doing in the other areas around data centers. You know, there’s 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. So we have done a great job in what’s been public and other opportunities that we’re working on to provide firm transportation through our big inch pipelines throughout the country.

As we mentioned earlier, we have over 230 Bcf of storage and expanding on that as we speak to be able to provide the, you know, pretty much 100% reliability that’s required by these data centers.

Dylan, Financial Executive, Energy Transfer0: Perfect. My quick follow-up is, you mentioned obviously Oracle. Obviously, you’re dealing with Fermi and NT Energy, and so both those companies are indicating a much stronger demand. I’m just trying to understand, if they do 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?

Mackie McCrea, Executive, Energy Transfer: That is back again. Absolutely. I mean, wherever there is a need for natural gas supply, there’s 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’s ironic how you can almost lay our pipelines along many of those corridors. So we’re extremely well positioned with our big inch, gigantic 42-inch pipeline systems throughout, really the country, but especially Texas and some of the other states like Louisiana. Nobody’s better positioned, and yes, we can upsize, loop, add compression, and provide whatever natural gas needs that anybody has along our systems.

Dylan, Financial Executive, Energy Transfer0: Thank you so much.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Michael Blum with Wells Fargo. Please go ahead.

Dylan, Financial Executive, Energy Transfer1: Thanks, Ted. Good morning, everyone. Wanted to ask on Waha, you know, pricing has just been, you know, as you know, very volatile lately, negative in Q4, spiked Q1 with the storm. So can you just remind us how much open capacity you have to capture spreads there? And, because I know you’ve also turned up a bunch of that lately.

Mackie McCrea, Executive, Energy Transfer: Yes, unfortunately or fortunately, we have turned up a lot of that lately. That’s what helped us get Hugh Brinson and other projects done. That’s just the nature of the business. But we still have about 160,000 Mcf a day that we’re benefiting from wherever the spread is from a day-to-day basis. And we’re pretty excited about Hugh Brinson coming on, really opening up the basin for everybody and to benefit the producers.

Dylan, Financial Executive, Energy Transfer1: Got it. Thanks for that. Then you and your competitors are all expanding frac capacity at Mont Belvieu. So I’m, I’m curious if you’re seeing

Speaker 4: ... any change in rates for fractionation with all this new capacity anticipated into the market? Thanks.

Mackie McCrea, Executive, Energy Transfer: Yeah, probably of all the segments we have, the NGL transportation and fractionation segment has, has become the most competitive. There tends to be an overbuild. We’re heading toward an overbuild a little bit in the NGL transport. Not sure on the fractionation, but once again, we always answer questions like this in that we really don’t, I wouldn’t say care, but we don’t worry about what our competitors are building. Our jobs are to build assets, fill them up, and keep them full for as long as possible, and we feel real good about that of completely filling up our natural gas transportation and then ramping up our Frac IX as we bring it online at the end of this year.

Speaker 4: Thanks, Mackie.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Elvira Scotto with RBC Capital Markets. Please go ahead.

Speaker 2: Hey, good morning. Good morning, everyone. Thanks for taking my question. I guess with the new growth projects that you announced and this, you know, big opportunity set that you see ahead, where do you think kind of annual growth CapEx could shake out over the next few years?

Mackie McCrea, Executive, Energy Transfer: Yeah, this, Elvira, thanks for that. Obviously, when you look out and you go over all these projects that we’ve been talking about, there’s, there’s a whole, whole lot more of them in the queue here actually, that we’re looking at. So it’s hard. We don’t generally give growth guidance like that out there, but you can see that, we’ve given the-- came out early with the 5-5.5, and with everything we’re talking about, we feel like it’s gonna stay pretty strong. So it’s probably a little bit early to, to give that guidance, but it’s clearly a lot of, a good projects that we have, have to look at. I don’t know, Dylan, if you wanna add a little bit more to that, but.

Dylan, Financial Executive, Energy Transfer: Sure, Elvira. You know, one thing as we look out, one thing to remember is, when we talk about our growth capital, growth capital guidance that we put out for this year, we’re not as concerned about cash flow and staying within cash flow there. When we look at long term, where we really-- we really govern this, is staying within leverage targets. So as you look out, you know, we have, 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. And so I think we’re really set up well to be able to fund whatever Mackie and the team put together here over the next few years in this great opportunity set that we have in front of us.

Speaker 2: Great, thanks. Then just one quick follow-up on the project with Enbridge. What’s it gonna take to get to SID? What else is required at this point?

Dylan, Financial Executive, Energy Transfer: Yeah. So, I’ll let Enbridge kind of comment on what is required on their side. But from our perspective, you know, we’re ready. We’ve got the design systems in place, and you know, there’s a little bit of work we need to do, obviously, to make this work. But we’re just in the commercialization phase, so continuing to have discussions, productive discussions with customers in Canada.

Speaker 2: Great. Thank you very much.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Zack Van Everen with TPH. Please go ahead.

Dylan, Financial Executive, Energy Transfer5: Hi, all. Thanks for taking my question. Maybe starting on the Oracle 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?

Mackie McCrea, Executive, Energy Transfer: Yeah, this is Mackie again, but that is kind of confidential. We’re not gonna 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 middle of the year. So we’re well positioned to be able to provide whatever gas supplies that they will need as they build out their data center.

Dylan, Financial Executive, Energy Transfer5: Got it. Makes sense. And then one more on Hugh Brinson. You know, you talked to more and more backhaul contracts coming online or, you know, getting signed. What, in your eyes, or what amount of gas do you think will actually make it to Carthage, if any? Or do you guys think most of that will be absorbed in the Dallas kind of Abilene area?

Mackie McCrea, Executive, Energy Transfer: Gosh, if we had that crystal ball, we’d certainly think differently about different pipes and stuff, but who knows? You know, as we think about it, there’s gonna be 10 or 11 Bcf of new pipeline capacity built out of the Permian. There’s several 48-inch pipes and 42-inch pipes being built out of Katy over into Louisiana. Got a bunch of pipes in North Louisiana heading south, and we have a ton of pipes with capacity, so who knows where the pinch points will be? But the message really from us is this: There’s nobody that can predict and answer that question. Where’s the most of the gas gonna be? Where’s the least pipe? But what we can do is take the least priced gas and transport it to the market that’s most needed in most areas of the United States.

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

Dylan, Financial Executive, Energy Transfer5: Got it. Appreciate the time. Thanks.

Dylan, Financial Executive, Energy Transfer2: The next question comes from Jason Gabelman with TD Cowen. Please go ahead.

Speaker 4: Yeah, morning. Thanks for taking my question. You’ve mentioned-

Dylan, Financial Executive, Energy Transfer6: ... potential to FID or a high likelihood of FID-ing projects across 13 states, related to power. You know, that obviously sounds like a high number on the surface. So wondering if you could give us a flavor of what those projects look like, if they’re more like cloud burst or the Oracle-type projects, and if that number has grown since the prior call?

Mackie McCrea, Executive, Energy Transfer: This is Mackie, and Adam, if he wants to follow up with this, he’s closer to a lot of this. But once again, I’ll give accolades to our data center teams, both one led by Adam and one led by Beth. We’re chasing every opportunity to provide gas or natural gas-fired generation for data centers. We’re well positioned with all of our, our pipelines. As we mentioned, we’re talking to, you know, 150+ different opportunities, and it seems like a new one or two come in every day. We have some deals that we’ve already done where there are some options data centers can exercise and take some capacity on us. So we’re—it’s across the board of the opportunities that we are chasing and negotiating.

We’ve been very successful so far, and 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, Executive, Energy Transfer: This is Adam. I just add that in terms of, like, project scope, they really range in size and go anywhere from kind of the new, you know, longer haul, new pipelines, to just interconnects that are, you know, like Mackie mentioned earlier, sitting right on top of our system, where at these crossroads of transmission, fiber, and our assets, and are simply just installing a new interconnect. So, the scope really varies from, you know, simple interconnects to bigger pipeline projects.

Dylan, Financial Executive, Energy Transfer6: Got it. Great. And my follow-up is more specific to the quarterly results. In the press release, there was mention of this regulatory order impacting prior period and current period rates. So 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 it was a net benefit on the quarter and should provide a modest uplift of future earnings. Thanks.

Adam, Executive, Energy Transfer: Sure. This is Adam again. I’ll hand it over to Dylan for kind of the second half of your question on the looking forward. But to start, let’s just say we’re extremely happy with kind of 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 kind of changing the index methodology. And last year, this FERC issued an order allowing pipelines to recover those lost revenues. So that’s what those one-timers reflect, and Dylan can kind of chime in on what it looks like going forward.

Dylan, Financial Executive, Energy Transfer: Yeah, yeah, Jason, so why don’t I just walk you through real quickly here, or wrap up on the quarter and the one-time impact, so we can kind of help you get a clean quarter to help how things are going to look going forward. On the NGL segment, we had $56 million from this regulatory order. That was a one-time positive. Get a little carryover effect from where that sets the rates now, but that’s primarily one time there. We also had a negative $58 million on the timing of the hedge gains around our hedge NGL inventory and a $14 million impact from the fog at Nederland. Both of those, so that $72 million total, we expect to recoup in the first quarter, so that’s a big boost moving into 2026 there. That’s a net negative 16 on NGL.

Crude picked up 19 one time from the regulatory order, and midstream lost 14 from transport fees that it pays on that regulatory order. It also had about $20 million from producer shut-ins in the Permian, where we saw some shut-in gas due to low, really negative pricing in Waha, for a -34 total net at midstream. And then the big one was a $60 million in transaction expenses it saw unrelated to closing of the Parkland transaction. If you put this all together, clean up the quarter, you’ve got a net negative about $90 million for that fourth quarter here that you’d want to add back to get a clean quarter. And like you said, you’ve got $70+ million that we expect to recoup of that in the first quarter.

Dylan, Financial Executive, Energy Transfer6: Great. That’s, that’s super helpful. Thank you.

Dylan, Financial Executive, Energy Transfer2: This concludes our question-and-answer session. I would like to turn the conference back over to Tom Long for any closing remarks.

Mackie McCrea, Executive, Energy Transfer: Yeah. Once again, thank all of you for joining us today, but also a lot of appreciation for some very, very good questions, very good dialogue and discussion on this. As you can see, we’ve got a lot of great things to talk about with these projects, not just for, you know, not just for 2026, but for a long time into the future, like Mackie was mentioning. So thank all of you. We look forward to all your follow-up questions. Please, please get a hold of our IR team, and we’re happy to jump on the call with you again. Thanks so much.

Dylan, Financial Executive, Energy Transfer2: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.