Energy Transfer LP (NYSE:ET) Q4 2025 Earnings Call Transcript

Energy Transfer LP (NYSE:ET) Q4 2025 Earnings Call Transcript February 17, 2026

Energy Transfer LP misses on earnings expectations. Reported EPS is $0.25 EPS, expectations were $0.3728.

Operator: Good morning, and welcome to the Energy Transfer Fourth Quarter 2025 Earnings Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Tom Long, Co-Chief Executive Officer. Please go ahead.

Thomas Long: 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 the 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 adjusted, 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. And 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 onetime $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 ArkLaTex regions. Results were partially offset by a onetime 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 onetime $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 billion and $5.5 billion, excluding SUN and USA Compression. We expect approximately 2/3 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 I and II, as well as continued system build-out in the Permian Basin.

In addition, approximately 1/4 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 buildout 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 rail 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 the 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 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 2 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. 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 in 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 2 projects is expected to be up to $535 million and $110 million, respectively, depending on the final shipper volume elections. And 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 3 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 3 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 MMBtus 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.

And 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 3 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 a 10-megawatt natural gas-fired electric generation facility continues, and we expect our third facility, which will be located at our Grey Wolf processing plant, to be in service in the first quarter of 2026. The remaining 5 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 I and II 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 2 ethylene cargoes in December of 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 and $17.85 billion compared to the previous range of between $17.3 billion and $17.7 billion. This change in guidance is solely attributable to the USA Compression’s acquisition of J-W 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 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 shift provides 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 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 we’ll 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 4x to 4.5x 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.

Q&A Session

Operator: [Operator Instructions] The first question comes from Theresa Chen with Barclays.

Theresa Chen: 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 Hugh Brinson as an example in the multiple life of service and revenue opportunities on that system? And 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 McCrea: Hello, this is Mackie. Thanks, Theresa. Yes, 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 for 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 Hugh Brinson able to move a lot of volume from west to east, but 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 into the Southeast.

So 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 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 midyear. That feeds into our frac that comes online in the fourth quarter. That feeds on to the Flexport expansion that we just completed in 2025. So just an incredible future for 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 transport of NGLs in the Northeast and see that continued 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 at general electricity for data centers, for population growth, for manufacturing facilities. All the power plants that Tom just talked about that our team has done such a good job in Oklahoma. To the best of my knowledge, I don’t think any of that data center. 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 going to be over the next 10 or 15 years because of our asset footprint throughout the United States.

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 bring online downstream assets recently and through the year and moving their own volumes back on to their own systems as a result. . Can you remind us how much third-party downstream Permian Y-grade 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 doesn’t come from your own processing?

Marshall McCrea: Yes. 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 2 Mustang Draw, both of those together, 550,000 Mcf a day, that’s approaching 85,000 to 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 intrastate transportation fracking and export business. I don’t know the exact percentage.

Dylan Bramhall: No, no, you — we’re about 60% of our own volumes, 40% third-party, and that affiliate volume number continues to grow. So we’ll keep trending — that 60% will trend up higher as we move through the year.

Operator: The next question comes from Gabe Moreen with Mizuho.

Gabriel Moreen: 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?

Marshall McCrea: This is Mackie again. Let me kind of step back a little bit. Energy Transfer had 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 in our systems, but also barrels that we’re chasing on third-party systems. We can’t afford to take that business. We’re going to fill up that NGL pipeline. And if we need to loop another pipeline west to Eastern Texas, that will be a new project for natural gas.

Gabriel Moreen: 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 market? And also to what extent that may or may not have benefited you guys financially here in the first quarter?

Marshall McCrea: Yes. With Tom’s leadership and Greg and Daniel and getting our operations team not only offer our assets safely, efficiently and profitably, but we also pride ourselves on times like this when it’s critical to move energy to the market and create, in this case, electricity in tough times. We proved ourselves during Uri, paid off in a big way. The same way this last storm that came in, in January, we were prepared as good as we could be. The negative, positive, however you want to look at it is that the industry got prepared. They saw what happens if you have an asset that are prepared, they’re line-pack storage. You’ve 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 to our pipeline systems as well as coming out of storage. So yes, 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 day period in Texas and throughout the country.

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

Jean Ann Salisbury: I heard in your comments that there could be some early volumes on Hugh Brinson? I think that with Blackcomb getting pushed to the fourth quarter, there could really be some value to those. Will those volumes go into your third-party customers? Or would that kind of all go to ET? And any sense of how early those could structure in?

Marshall McCrea: Yes, this is Mackie again. First of all, let me just say we keep talking about our teams, but we’ve got 1 of the best E&C teams, probably 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 going to be real careful on — 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 as how we contractually and regulatory are allowed to do so. But we’re going to do everything we can to get volumes, new egress out of the Permian Basin because it’s much needed for the producers who are suffering from negative price seeing out of the Waha.

And so it’s going to 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 kind of what we think the volume might be and how early it might be. But right now, we’re going to stand by. We’re going to have some volumes early in the fourth quarter. We don’t know exactly when or how much.

Jean Ann Salisbury: That makes sense. 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 to 10 years, is there any technical limit to how much the DAPL system could switch over to running Canadian heavy and set?

Adam Arthur: Jean Ann, this is Adam. So as we’re talking about MLO 2, which I think is what you’re referring to, we’ve definitely done a look. And first and foremost, we’re going to 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 scope 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.

Operator: The next question comes from Keith Stanley with Wolfe Research.

Keith Stanley: So more of your peers are giving multiyear EBITDA growth expectations. How should we think about medium-term growth for Energy Transfer, if you’d put any framework around that?

Dylan Bramhall: Keith, this is Dylan. Let us answer the question this way. But when we set our long-term distribution growth rate of 3% to 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. But we said that, that basically sets the floor for what we believe we can achieve for our long-term growth rate.

Keith Stanley: Got it. That’s helpful. Second one on — so you’ve talked a lot about Texas NGL recontracting 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?

Marshall McCrea: This is Mackie again. Yes, what — you do that. What an incredible set of assets we have up there. We built it a franchise with our Mariner pipelines going west, but also the majority of that 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 continue to perform. We’re not going to get into strategies about when contracts fall off and when we’ll 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 ways to expand that business and continue to be the major dominating player for moving natural gas liquids out of the Marcellus, Utica areas.

Operator: The next question comes from Julien Dumoulin-Smith with Jefferies.

Julien Dumoulin-Smith: Let me just follow up on a couple of clean-up items here. On the Desert Southwest project, can you talk a little bit about the pro forma economics? I mean, obviously, moving to 48, good stuff. But how are you thinking about just setting the expectations on economics there? And then going back to Jean Ann’s question from a moment ago. Looking at the DAPL side, can you talk about maybe some of the tariffs and how you think about that maybe relative to what you saw in the last decade on tariffs to give a little bit of a preliminary sense of what pro forma economics might look like for the 250 or more as it maybe that you’re looking at there?

Marshall McCrea: You bet. This is Mackie. 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 want to over-exaggerate expectations. But right now, that type of project, that pie — everything coming in the distance and diameter and throughput, we think that will be probably 1 of the better rate of return projects that we’ve ever built just as far as a one-way flow.

We always mention Hugh Brinson is going to generate money in multiple directions. But going from east to west, New Mexico provide natural gas supplies to markets along Southern New Mexico and then into the just fast-growing population, probably data centers, et cetera, et cetera, in Phoenix, that’s going to be 1 of the better projects that we’ve built in a long time.

Adam Arthur: Julien, 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 well beyond kind of the mid-2030s. And 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 MLO 2 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.

Julien Dumoulin-Smith: Yes. I hear it. Mackie, 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-plus that you alluded to a second ago. I mean, the scope seems pretty real time that we’re 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 in even the next 12 months? I know you guys just did it here, but not being facetious.

Marshall McCrea: 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 look 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 to Texas. And I can go on and on, but we have multiple pipelines in those ditches. We’re adding our Phase IX. Very likely, we’ll 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 Phoenix area grows with demand for natural gas for a number of reasons, there’s certainly going to be opportunities to look at 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.

Operator: The next question comes from John Mackay with Goldman Sachs.

John Mackay: Why don’t we stay on DSW. You guys upsized — that you kept your time line intact. Can you just remind us 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 as you execute?

Marshall McCrea: Yes. I’ll say once again, our E&C team is so good. On all these projects, we try to look ahead 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 a day.

John Mackay: And then sorry, just in terms of construction timing, the permits, et cetera.

Marshall 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’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 the existing corridor of pipelines and utilities. So it’s in a really good area where we’re laying this to, and we’re — right now, a worst case will 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 is going as planned.

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

Marshall McCrea: Yes, as we said earlier, we — as a strategy in transport, we’re looking at all of our assets, not just our pipeline assets and repurposing those, but it’s also our terminals. And so as 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’s — it has a really good draft in a really good terminal, and we do expect it to create some kind of business going forward in that terminal.

Operator: The next question comes from Manav Gupta with UBS.

Manav Gupta: You guys are obviously leading from the front when it comes to signing up with 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 [ 5-9 ] in terms of 99.99% utilization. So can you talk a little bit about how ET can 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?

Marshall McCrea: You bet. And I’ll give accolades to Adam, who’s next to me and his team and what they’ve done in Texas and a few other states. And then Beth and where — her team are doing in the other areas around data centers. 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 actually, 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 etch pipelines throughout the country. And then as we mentioned earlier, we have over 230 Bcf of storage and expanding on that as we speak to be able to provide the pretty much 100% reliability that’s required by these data centers.

Manav Gupta: Perfect. My quick follow-up is you mentioned, obviously, Oracle. Obviously, you’re dealing with Fermi and Entergy. And so both those companies are indicating a much stronger demand. And 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?

Marshall McCrea: Yes, this is Mackie 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, out — 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 is better positioned. And yes, we can upsize, loop, add compression and provide whatever natural gas needs that anybody has along our systems.

Operator: The next question comes from Michael Blum with Wells Fargo.

Michael Blum: Wanted to ask on Waha. Pricing has just been, as you know, very volatilely negative in Q4, expect 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.

Marshall McCrea: 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 really to benefit the producers.

Michael Blum: Got it. And then you and your competitors have all — are all expanding frac capacity at Belvieu. So I’m curious if you’re seeing any change in rates for fractionation with all this new capacity anticipated to enter the market?

Marshall McCrea: Yes. Probably of all the segments we have, the NGL transportation and fracking segment has become the most competitive. There tends to be an overbuild. We’re heading to an overbuild a little bit in the NGL transport, not sure on the frac. 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 — enjoy filling up our natural gas transportation and then ramping up our Frac IX as we bring it online at the end of this year.

Operator: The next question comes from Elvira Scotto with RBC Capital Markets.

Elvira Scotto: I guess with the new growth projects that you announced and this big opportunity set that you see ahead, where do you think kind of annual growth CapEx could shake out over the next few years?

Thomas Long: Yes. Elvira, thanks for that. Obviously, when you look out and you pull over all these projects that we’ve been talking about, there’s a 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 to 5.5. And with everything we’re talking about, we feel like it’s going to stay pretty strong. So it’s probably a little bit early to give that guidance, but it’s clearly a lot of good projects that we have to look at. I don’t know, Dylan, if you want to add a little bit more to that?

Dylan Bramhall: Sure, Elvira. One thing as we look out, 1 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, we’re really governing this is staying within leverage targets. So 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. 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 and this great opportunity set that we have in front of us.

Elvira Scotto: Great. And then just one quick follow-up on the project with Enbridge. What’s it going to take to get to FID? What else is required at this point?

Adam Arthur: Yes. So I’ll let Enbridge kind of comment on what is required on their side. But from our perspective, we’re ready. We’ve got the design, the systems in place. And 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.

Operator: The next question comes from Zach Van Everen with TPH.

Zackery Van Everen: 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?

Marshall McCrea: Yes. This is Mackie again. But that is kind of confidential. We’re 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 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.

Zackery Van Everen: Got it. Makes sense. And then one more on Hugh Brinson. You talked to more and more backhaul contracts coming online or 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?

Marshall McCrea: Gosh, if we had that crystal ball, we’d certainly think differently about different pipes and stuff. But who knows? As we think about it, there’s going to 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. We’ve 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 who can predict an answer to that question. Where most of the gas can be, where is the least. 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 love the position we’re in, and we’ll be able to capitalize on whatever dynamics happened on the production front and the ebbs and flows from Permian Basin to East Texas to Haynesville. We just love the position we’re in, not knowing exactly where all this is headed.

Operator: The next question comes from Jason Gabelman with TD Cowen.

Jason Gabelman: You’ve mentioned potential to FID or a high likelihood of FID-ing projects across 13 states related to power. 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 CloudBurst or the Oracle type projects and if that number has grown since the prior call?

Marshall McCrea: This is Mackie. 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 spotter generation for data centers. We’re well positioned with all of our pipelines. As we mentioned, we’re talking to 150-plus different opportunities, and it seems like a new 1 or 2 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 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 Arthur: And this is Adam. I’ll just add that in terms of like project scope, they really range in size and go anywhere from kind of the new longer haul new pipelines to just interconnects that are — like Mackie mentioned earlier, sitting right on top of our system. We’re at the crossroads of transmission, fiber and our assets and are simply just installing a new interconnect. So the scope really varies from simple interconnects to bigger pipeline projects.

Jason Gabelman: Got it. Great. And my follow-up is more specific to the quarterly results. In the press release, there was a mention of this regulatory order impacting prior period and current period rates. So I wonder 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 modest uplift of future earnings.

Adam Arthur: 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 hurt the FERC under her leadership have taken so far. As far as the index issue specifically, in ’22, 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 Bramhall: Yes, Jason. So why don’t I just walk you through real quickly here or wrap up on the quarter and the onetime 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 onetime positive. Get a little carryover effect from where that sets the rates now, but that’s primarily onetime 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 in Nederland. Both of those, 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 onetime from the regulatory order, and midstream lost 14 from transport fees that it pays on that regulatory order and 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 or negative 34 total net at midstream. And then the big 1 was a $60 million in transaction expenses. It’s on related 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 we said, you’ve got $70-plus million that we expect to recoup it that in the first quarter.

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

Thomas Long: 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 2026, but for a long time into the future, like Mackie was mentioning. So I thank all of you. We look forward to all your follow-up questions, please get a hold of our IR team, and we’re happy to jump on the call with you again. Thanks so much.

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