Energy Transfer Equity, L.P. Aktie

Good morning, and welcome to the Energy Transfer First Quarter 2026 Earnings Call. [Operator Instructions]

Please note this event is being recorded. I would now like to turn the conference call over to Mr. Tom Long, Co-Chief Executive Officer. Thank you, and over to you.

Thank you, operator. And good morning, everyone, and welcome to the Energy Transfer First Quarter 2026 Earnings Call. I'm also joined today by Mackie McCrea, Dylan Bramhall, 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 take a look at the press release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities.

As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended March 31, 2026, 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 by going over our financial results. For the first quarter of 2026, we generated adjusted EBITDA of approximately $4.9 billion compared to approximately $4.1 billion for the first quarter of last year. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2.7 billion compared to approximately $2.3 billion for the first quarter of 2025. These results were supported by strong operations, including record midstream gathering volumes, NGL fractionation volumes, NGL export volumes and crude oil transportation volumes for the quarter. And for the first quarter of 2026, we spent approximately $1.5 billion on organic growth capital, primarily in the intrastate, NGL and refined products, midstream and interstate segments, excluding SUN and USA Compression CapEx.

Turning to our 2026 guidance. As a result of our strong first quarter performance across our segments as well as revised expectations for the rest of 2026, we now expect our 2026 adjusted EBITDA to range between approximately $18.2 billion and $18.6 billion compared to the previous range of between approximately $7.45 billion (sic) [ $17.45 billion ] and $17.85 billion. This includes a beat of approximately $500 million and the capture of our full year optimization target in the first quarter as well as the expectations for continued outperformance for the balance of the year.

Now turning to organic growth capital guidance. We now expect 2026 organic growth capital guidance to be between approximately $5.5 billion and $5.9 billion compared to our previous guidance of approximately $5 billion to $5.5 billion, excluding SUN and USAC. This increase is primarily a result of the addition of several new growth projects, including the construction of the new Springerville Lateral off our existing Transwestern Pipeline, the construction of pipelines and meter stations to provide natural gas to various power plants and data center sites in Oklahoma and Arkansas, accelerated timing on longer-term projects like Desert Southwest and FGT capital spend and gathering system and compression build-out in the midstream segment, primarily in the Permian Basin associated with recent contract and acreage dedication extensions.

I will provide additional details about these projects later in the call. Beyond these projects, we continue to have a significant backlog of opportunities that are expected to support future growth.

Now turning to our results by segment for the first quarter, and we'll start with NGL and refined products. Adjusted EBITDA was approximately $1.2 billion compared to approximately $978 million for the first quarter of 2025. We saw higher throughput across our Gulf Coast pipeline operations and record performance at our Mont Belvieu fractionators.

In addition, new chilling capacity placed into service last year contributed to a $50 million increase in earnings as well as record export volumes from our Nederland terminal in the first quarter. This more than made up for fog delays experienced in the fourth quarter of 2025. During the first quarter of 2026, we realized higher gains of $65 million due to the timing of the settlement of NGL and refined product inventory hedges, which offset losses realized in the fourth quarter of 2025.

Results for the quarter also included an increase of approximately $50 million from higher premiums from the sale of propane and butane for both export and domestic supply as well as an approximately $25 million increase due to inventory write-down losses realized in the first quarter of last year.

For midstream, adjusted EBITDA was approximately $887 million compared to approximately $925 million for the first quarter of 2025. Base business earnings increased primarily due to growth in the Permian Basin, where we saw volumes up 8% related to new and upgraded processing plants brought online since the first quarter of last year.

In addition, we saw a $25 million decrease due to lower NGL and natural gas prices compared to last year. As a reminder, the first quarter of last year included the recognition of revenue of $160 million from Winter Storm Uri. For the crude oil segment, adjusted EBITDA was approximately $869 million compared to approximately $742 million for the first quarter of 2025.

During the quarter, we saw continued growth across several of our crude oil pipelines and gathering systems. Results also included a $60 million increase related to favorable impacts to our crude oil inventory value as a result of rising crude oil prices. We expect these gains to be mostly offset with hedge losses during the second quarter of this year.

In addition, we recognized $43 million of revenue that had previously been reserved, related to the recontracting and extension of a legacy shipper contract during the recently completed successful DAPL open season. And we had lower expenses due to a $43 million adjustment to an accrual for a litigation-related contingency.

In our Interstate Natural Gas segment, adjusted EBITDA was approximately $519 million compared to approximately $512 million for the first quarter of 2025. This increase was primarily due to higher contracted volumes and higher rates on several of our pipelines, including Panhandle Eastern, Trunkline, Florida Gas and Transwestern. And for our Intrastate Natural Gas segment, adjusted EBITDA was approximately $437 million compared to approximately $344 million in the first quarter of 2025. This was primarily due to an increase of approximately $100 million from Winter Storm Burn.

Results for the first quarter show how incredibly well positioned our assets are across the country. Combining our extensive pipeline network, our storage facilities and our terminals with our exceptionally experienced optimization and operating teams, we were able to capitalize on quickly changing dynamics and market volatility.

For a closer look at some of our major projects, and I'll start with the natural gas side of our business, where we continue to see significant demand for our services. We are making good progress on our Desert Southwest Pipeline project. In March 2026, Transwestern Pipeline initiated the FERC prefiling process for the project as previously scheduled, and we expect to file the formal certificate application with FERC in the fourth quarter of this year.

In April, as the continuation of our comprehensive stakeholder engagement program, we hosted 15 open houses in communities along the entire proposed pipeline route throughout Texas, New Mexico and Arizona.

Our teams continue to actively engage with elected officials, county leadership, landowners and associated communities along the route to communicate project information and updates, and we have engaged with over 500 stakeholders to date. Our discussions have continued to be very positive as existing and potential stakeholders learn more about the expected economic benefits and realize the critical need for a dependable supply of natural gas to help with the transition from coal-powered generation to natural gas-powered generation and to help address significant power needs in the coming years, driven by population and demand growth in Arizona and New Mexico markets.

We expect this pipeline to be in service, providing a reliable energy source by the fourth quarter of 2029. On the existing Transwestern Pipeline, we recently approved the construction of the new Springerville Lateral, an approximately 120-mile, 30-inch pipeline that will have a capacity of approximately 625 million cubic feet per day and extends south to new natural gas-powered generation that is expected to replace 2 coal-fired plants. This project is backed by 20-year agreements and is expected to be in service in the fourth quarter of 2029. Total growth capital for this project is expected to be approximately $600 million.

New construction of our Hugh Brinson Pipeline is going well. We continue to expect Phase 1 to be in service in the fourth quarter of this year upon the full build-out of the 400-mile pipeline and associated compression required to move 1.5 Bcf per day of gas to customers' contractual delivery points. However, if we stay on our current schedule, we will have the ability to begin flowing some gas early in the third quarter, which is prior to placing Phase 1 into service. And we continue to expect Phase 2, which includes additional compression to be in service in the first quarter of 2027.

The pipe is fully contracted from West to East, and we also have a growing amount of backhaul volumes committed that are expected to add significant upside.

Turning to Florida Gas Transmission or FGT. In February, we completed open seasons for 2 new projects that are supported by 15- to 25-year long-term agreements with anchor shippers. The Phase 9 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 approximately 90 miles of pipeline looping as well as new and upgraded compression with an anticipated capacity of approximately 525 million cubic feet per day. We recently locked in pipe for delivery at the end of 2027 and compression for delivery in the first quarter of 2028, and we continue to expect the project to be available for service in the fourth quarter of 2028.

The South Florida project is designed to enhance the reliability of critical infrastructure and increase overall deliveries in South Florida. The project has a condition precedent, but once we reach FID, it will consist of the construction of an approximately 40-mile extension with a capacity of approximately 230 million cubic feet per day, along with compression and a new meter station and is expected to be available for service in the first quarter of 2030.

The Energy Transfer share of the cost for these 2 projects is expected to be approximately $565 million and approximately $110 million, respectively, depending upon final shipper volume elections. We continue to make progress on a new storage cavern at our Bethel natural gas storage facility, which is expected to double our working gas storage capacity at the facility to over 12 Bcf. In February, our intrastate power team added connections to serve 3 new power plant loads in the state of Oklahoma. We have since added a fourth connection for a total of approximately 300 million cubic feet per day of new gas supply. The first of these connections is in service with 2 more expected in service in the third quarter of this year. The remaining connection is expected to be in service in the fourth quarter of 2028. These connections are supported by long-term contracts with investment-grade counterparties.

In addition, we have entered advanced negotiations to serve another 400 million cubic feet per day of new power plant demand in Oklahoma. And since our last earnings call, Energy Transfer has entered into agreements to provide long-term firm natural gas transportation services through our Texas intrastate system to support the Nexus Hubbard Campus located in Central Texas, where Nexus is constructing a behind-the-meter, AI hyperscale campus powered by on-site natural gas generation.

Initial volumes are expected to be approximately 150 million cubic feet per day with certain rights by the transporter to increase its capacity upon election. Costs associated with this project are expected to be fully reimbursed, and it is expected to be in service by the end of this year. In addition, we recently entered into an LOI to provide approximately 150 million cubic feet per day of firm natural gas transportation service through our EGT pipeline to support a new data center site in Arkansas. The facility is expected to be in service in mid-2027.

Energy Transfer also previously 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. To facilitate flow of this gas, we plan to construct an 18-mile lateral off of our Tiger pipeline for which our customer recently exercised their option to upsize the pipeline lateral to 36 inches, and they continue to have an option to increase their commitment to up to 1 Bcf per day.

In addition to these projects, we have multiple ongoing discussions with power plants to provide significant volumes and associated transportation revenues across 15 states which have a high likelihood of reaching FID. Now looking at our Permian processing expansions. The 275 MMcf per day Mustang Draw I processing plant is currently being commissioned and is expected to be in full service next month, and we expect volumes to ramp up quickly. And we continue to expect our 275 MMcf per day Mustang Draw II plant to be in service in the fourth quarter of this year.

In our NGL segment, we placed the Gateway NGL pipeline debottlenecking project into service in the first quarter of this year, providing increased deliveries of Delaware Basin liquids to Energy Transfer's NGL fractionation complex in Mont Belvieu. Construction is also underway on a new 3 million-barrel ethane storage cavern at Energy Transfer's NGL fractionation complex at Mont Belvieu. The cavern, which is expected to be in service in the second half of 2027 will help support our ninth fractionator at Mont Belvieu that is expected to be in service in the fourth quarter of this year as well as future ethane export expansions.

At Nederland, we've recently extended the vast majority of our ethane export agreements into 2041, adding 10 years to the current contracts. We are hopeful to be in the position for incremental Nederland ethane expansion in the coming months. In our crude oil segment, we continue to work with Enbridge on a project to provide capacity for approximately 250,000 barrels per day of light Canadian crude oil through our Dakota Access Pipeline. The open season is underway, and we still expect to take FID of this project by mid-2026.

In addition, we have approved an expansion of the Bayou Bridge crude oil pipeline, which is expected to increase the capacity to up to approximately 600,000 barrels per day depending on destination and product mix. This expansion is underpinned by a 10-year term extension and volume increase from a demand pull customer and is expected to be in service in Q1 of 2027.

I think as all of you can see, we had a lot of great things happen in the first quarter and many more exciting things on the way, which contributed to our increased EBITDA guidance for 2026. Our guidance each year is based upon expectations for the base business with minimal optimization included.

However, in 5 of the last 8 years, we have seen large spreads, optimization and other opportunities that have provided significant upside to our base business. These kinds of benefits, while one-time in nature, highlight the unique ability of our business to consistently capture significant upside during market volatility. While additional upside is expected to be dependent upon the duration and impact of current market disruptions and resulting commodity prices, our assets remain incredibly well positioned to continue maximizing on these opportunities.

As a result, we are optimistic that some of the benefits we saw in the first quarter will carry over throughout the rest of the year, putting us in a position to achieve or exceed the high end of our guidance range.

Additionally, we continue to expect the ramp-up of growth projects, including our Flexport NGL export project, new Permian processing plants, Hugh Brinson and others, which we expect will contribute to continued growth in 2026. In particular, once our Hugh Brinson Pipeline is in service, it will be extremely well positioned to become a major U.S. header system that ties together our network of large diameter pipelines, providing significant future upside.

Our large slate of growth projects is contracted under long-term commitments and expected to generate mid-teen returns and considerable earnings growth over the next decade or more. Completing these projects safely, on time and on budget remains one of our top priorities for 2026. We also continue to see new growth opportunities across all aspects of our business demonstrated by the announcement of several new projects this quarter, and we remain extremely well positioned to help meet the substantial growth in demand for energy resources over many years to come.

As a result, we also remain very focused on capital discipline, targeting a long-term annual distribution growth rate of 3% to 5% and maintaining our leverage target of 4 to 4.5x EBITDA.

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

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

[Operator Instructions] We have the first question from the line of Michael Blum from Wells Fargo.

I wanted to just start kind of high level in light of the Middle East conflict that's ongoing, are you seeing any change in U.S. producer activity or messaging? And I guess in a similar vein, would you expect to see any permanent shifts in where global buyers will be sourcing their hydrocarbons, perhaps leaning more heavily on the U.S.? And are you seeing any of that in your discussions yet?

Michael, this is Mackie. As I look around the room, as you're asking that question, there's like 5 people that want to answer that question because we're so excited about where we sit and where our assets sit. And certainly, what's been going on in the world, there's a very clear redirection to the U.S. for all products, LNG, NGLs, oil, et cetera. And it really has emphasized the value of what this country offers and more importantly, what our partnership offers to deliver all these products around the world. If you talk about individual basins, it's all different. I think the major tenor throughout is optimism, not a rush to put a bunch of rigs in. But even as of yesterday, one of our bigger customers out in the Midland Basin, Diamondback, they announced they're going to upsize and bring in more rigs.

So I think we're going to see -- it's kind of slow moving, not a lot of talk, but I think it's very evident that we're going to see more and more rigs moving in as more countries and companies turn to the U.S. for supply regardless of how long that war may last. And an example is in North Louisiana, Haynesville, we're projecting about 800,000 Mcf of growth into our processing, treating and downstream assets in North Louisiana by August or September. But clearly, the producers in North Louisiana are drilling and are going to bring on DUCs as we proceed deeper into this year, and we think that's going to continue for many years to come. So we love where our assets are.

We're very excited about the future growth of drilling. Not real clear how quickly all the companies in all the basins are going to pick up, but the bottom line is there's going to be increased drilling, increasing DUCs, bringing on new wells from DUCs throughout the country, and we're very excited about where we sit.

Appreciate it. Maybe just to ask specifically on the LPG exports. First of all, can you just remind us what percent of your capacity is contracted versus open? And are you seeing any increase in demand for contracted capacity? And do you think potentially you could see length of contracts or just rates kind of trend higher over time?

Kind of yes to all of the above. As I mentioned earlier, whether we're meeting with companies or looking at building assets over here and/or buying products over here, everybody is turning to the U.S. So we're extremely well positioned there. Good or bad, our strategy as a company is looking long term.

So whether it's LPG or natural gas, whatever it is, we're looking to extend out into the 2030s and 2040s as much as our business as possible. So our team did a great job at good healthy rates of extending our LPG business well into 2030s. So regretfully, we don't have a bunch of spots where we have 4 or 5 ships where we could be printing a lot more money. But fortunately, we do have spots available. The Flexport, a project that we just completed that we're starting to fully ramp up. We do have at least 1 or 2 slots a month that we can benefit from these higher spreads. And to answer your -- the final part of your question, we do think this will bring about longer terms and stronger margins as time goes on as everybody leans on the U.S. for supply.

We have the next question from the line of Gabe Moreen from Mizuho.

I just wanted to ask about guidance. It sounds like on the one hand, in the slide, you didn't really shift your allocation between spread and commodity-based margin through the year and you're using the forward curves. On the other hand, I think, you noted in your remarks, you're hopeful to exceed guidance or the upper end of the guidance here if things persist.

Can you just maybe talk about some of the moving pieces? And I know it's pretty considerable and maybe sort of the assumptions on commodity versus forward curve and what you're really baking in for the rest of the year here with this guidance. Tom?

Sure, Gabe. Let me walk you through some additional thoughts rather on the full year guide. I think it will help clear some of this up. We had an incredible first quarter. Tom just walked through the fact that we beat our internal plan by $500 million plus achieved our full year target for optimization earnings. Out of the $500 million, I want to point out that about $300 million of that would probably be considered onetime as we describe it. And as Tom pointed out, we call it onetime, but we see this almost every year at Energy Transfer with our assets and people.

So how much of that really you call on timing is up to the individual, I guess. But then the rest of it is really a result of the tailwinds to the business. And so as you see, we raised guidance by $750 million at the midpoint. This is really based on line of sight to the continued outperformance across the majority of the segments. And it's everything. It's volumes, it's rates, it's spreads. And so that's why you didn't see us update that pie chart there. It's really permeating everything we do here. And a lot of this is a result of the conflict in the Middle East, making it clear, as Mackie pointed out, the need for the reliable U.S. energy supplies.

And so that's increasing the demand and the volumes and rates. And so while we -- in Energy Transfer, we pray for a resolution of this conflict, we feel that it's very likely that the supply and product flows will need an extended amount of time to return to some form of normalcy on the back end of this. It's likely it will never go back to exactly how it was pre-conflict. We saw this with the Ukraine conflict and today's issue just drive home even more the need to -- the reliability of the energy from the U.S. here. And so as we look through the balance of the year, from the commodity price standpoint, that midpoint of the guidance range, I think, you could say it is based on a conservative price deck going forward. And if prices remain anywhere near where they are right now, that will push us to the high end of the guidance range and potential to exceed that. And so I think that should help clear up how we're thinking about the balance of the year here.

And then maybe if I can just follow up with a question on Desert Southwest and the Springerville Lateral. I'm just curious whether the volume heading to that lateral was contemplated in the original 2.3 Bcf on Desert Southwest or whether there's potential of any upsizing to the base project. And then also as far as potential for further laterals along those lines? I know you've talked about the potential to upsize the pipe. And then lastly, on that, anything changed in terms of the regulatory approval or time lines given the lateral associated with the project now?

Yes, this is Mackie again. So kind of separate topics, talking about the Springerville Lateral, that's tied, as Tom mentioned, to the retirement of some coal plants, replacing it with natural gas-fired generation. We believe that the majority of that gas will come from either the San Juan Basin and/or from the Permian Basin. Are there other lateral opportunities off that? Sure. There's always going to be stuff we're looking at. Separate that from your question on Desert Southwest, absolutely, all along through to Mexico and especially in Arizona, there are numerous opportunities to lay laterals to different power plant opportunities and different customers.

So we -- our team is constantly chasing that. We there's a lot of volume, a lot of demand that we're chasing. And so we have 0 concerns about selling the remaining portion of that gas through our -- the largest pipeline that's ever been built in the U.S. once we complete it. So once again, like all of our assets, we're going to do the best we can to add value on assets that are already in the ground. And the Springerville customers can ultimately source their gas from anywhere on the TW system, but the vast majority of it will come from Permian Basin or San Juan.

We have the next question from the line of Theresa Chen from Barclays.

Going back to the macro side of things, assuming an uptick in U.S. production materializes and accelerates from here, can you talk about the operating leverage across your system to the extent where ET can handle incremental volumes without deploying additional CapEx? And more broadly, where do you see the critical bottlenecks likely to arise either for the industry or across your assets in particular? And how does that translate to additional opportunities for Energy Transfer?

Yes. Theresa, as far as the operational leverage, let me kick off, and I'll turn it over to Mackie to give some additional detail here. When you look at our systems, particularly in midstream, we've got a lot of capacity available or idle capacity we can bring back online quickly across the Mid-Con. We've got a lot of capacity in the Eagle Ford. We've got a lot of capacity in our gathering systems. in the Haynesville and in the Northeast. We've got some pipeline capacity throughout various pipeline systems, but we've got capacity to move NGLs out of the Permian Basin, the Eagle Ford. I think those would be the first places I would point where we have capacity either available or quickly available that we can bring online with little to no capital and be able to move significantly higher volumes. So that's probably what leads on the operational leverage. But Mackie, I don't know if you want to comment any more on bottlenecks in the system or.

Yes. Thanks, Dylan. Yes, as far as bottlenecks, makes me think about, for example, our NGL segment and as we -- as Tom read and as we released this morning in our press release is that we had record levels from the wellhead, so to speak. So from an NGL perspective, we had record transportation revenues and volumes. We had record fractionation volumes. We had record terminal volumes. We had record export volumes. So when you talk bottlenecks, we kind of try to stay ahead of it.

Right now, as everybody knows, we completed Flexport II. We are slowly ramping that up and benefiting from whether ethylene or ethane or propane are the best price margins, be able to benefit from that. But we're trying to stay ahead of it. As Tom mentioned earlier, we are way down the road and very optimistic on another announcement of a major ethane expansion. So the way to avoid bottlenecks is to stay ahead of it. And that's what we're trying to do is stay ahead of the production as it comes on. So we're building cryos as quickly as we can to fit the needs of our customers, downstream transport pipeline capacity as well as Frac. And in this case, export capabilities.

So outside of that, could you say there's a bottleneck in the Permian Basin today? Absolutely. By the end of this year, first part of next year, that bottleneck is going to open up, and there's going to be enormous opportunities for producers to drill away as much as they want to drill because there'll be plenty of capacity for a number of years to come. So -- but really bottleneck-wise, I don't really see anything anywhere else. We try to stay ahead of where the production and where our customers are growing and connecting that with the markets downstream and very excited about our ability to kind of stay ahead of that and create more value for our partnership.

Great. And for the gas transmission projects related to delivering gas supply for data centers or power generation in general, some of these expansions seem relatively capital light, so maybe not coming with a huge uplift in EBITDA from the project itself. But what proportion of them would you say have synergistic upstream opportunities where Energy Transfer brings the gas supply and/or can these projects can pave the way for expansion upstream of the current projects?

This is Mackie again. If you think about Hugh Brinson, and it's coming online, we're going to start ramping it up next quarter, and we will have a full Phase 1 in service by the end of the year. That gives us the ability to do a lot of things, as we've said in our statements before. We said today to swing volumes where volumes are needed, where the markets are the greatest demand. So if you look at that system and what Hugh Brinson does for our entire intrastate pipeline network in Texas, we are -- we already have deals. We're working on additional transactions where, to your point, not a lot of capital, but we're going to be able to flow more and more backhaul volumes out of the Maypearl area, south of Dallas-Fort Worth, out of East Texas, even from Katy, we're very close to signing a large transportation deal to a data center and the source supply is going to be Katy.

So we have such a fungible system that has the ability, especially with our massive storage capabilities in the Houston, North Texas area and growing and expanding those. We have enormous capacity to really grow our volumes in a lot of cases without adding much capital. So as we've said before, we look at our assets, especially our pipeline assets across the country, and we couldn't be more pleased and really more fortunate to be located in such great areas where data centers are built right on top of us, and we're able to benefit not only from normal flows like in Texas, West to East, but now we're going to be able to benefit in multiple directions, sourcing the best place supply for our customers to the market demand areas they're asking us to deliver gas to.

We have the next question from the line of Jeremy Tonet from JPMorgan.

Just wanted to continue with the bottleneck theme, if I could. Thinking about the Permian and thinking about the processing side specifically, just wondering if you could share any thoughts on how you think the cadence of future processing plants might unfold. We saw some competitors announce some new plants this quarter. So just wondering any color you can provide there and how you see that developing?

Okay. This is Mackie again. Yes, Brian and Alex and our G&P team have done such a great job. And yes, we hear about announcements from our competitors in their plants, and we just kind of pay attention to what we do. What we don't do is get out ahead of ourselves. We're not going to go out and build a bunch of cryos that aren't fully sold out and fully committed to.

So that's why maybe we haven't announced as many as some of our competitors especially in the future. But we're very excited about the 550,000 Mcf that we'll have on by the third quarter, one of those coming on here next month. And we will always take a look at when is the next one due to come on. And I'd be surprised if certainly not late third quarter to by the end of this year that our G&P doesn't come to us and say we need to add another one very likely in the Delaware. That's a little ahead of the game right now.

Our focus right now is to bring these cryos on that we're constructing today, and then we expect those to ramp up fairly quickly, but we'll do everything we can and we will stay ahead of the volume commitments that we have. And very excited, like I keep saying where our assets are, how well located our pipelines are to gather gas and bring into the cryos and then ultimately delivering into our downstream assets, both NGL and residue pipelines.

Got it. That's helpful. And then just switching to the Haynesville, if I could, the 800, you talked about coming this year, quite a large quantity there. I was just wondering if you could talk a bit more, I guess, on timing cadence of how that looks like? And is this really LNG pull? Or just any more color on how you see this unfolding over the course of the year?

Yes. I can't really speak to the ultimate market for all that. Just bottom line is the producers that have drilled are drilling and have DUCs have indicated to us that they're about to start really ramping up, bringing on gas -- as was said earlier, we expect to bring on net about 500,000 a day. That's -- a lot of that's treated. So we'll be treating it, processing it. And that will -- the vast majority, I think, all of it actually is going into our downstream pipes. Where the ultimate market is, sure, a lot of that will probably find its way to LNG markets, but most of those are third-party customers taking that transport, and we don't know the ultimate market.

Got it. If I could sneak in one last quick one, just as far as exports are concerned with crude oil refined products, wondering opportunities you see there in light of a global macro volatility.

This is Adam. So we've definitely seen a ramp-up across our docks on all products. So I think with the conflict that we talked about earlier, there's a clear demand for incremental U.S. energy and with the record export numbers that we've seen over the last couple of weeks be published, like we at ET are benefiting from our share of that for sure. So we expect that while this continues, there's definitely increased activity across the docks, both from a crude, LPG and refined products perspective. But then as Dylan alluded to earlier, even if we get back to some sense of normalcy, it will never go back, we believe, to kind of where we have been before and that increased demand will stay at levels elevated to before the conflict.

We have the next question from the line of Jean Ann Salisbury from Bank of America.

Can you comment on whether the ethane export contract extensions were at a similar rate to your existing rates or if there were a step down? And then you've kind of referenced this potential future expansion at Nederland for ethane. Can you just comment on whether that's partially due to the current Iran conflict bringing forward interest or if that had been kind of percolating?

This is Mackie again. Yes, one thing I guess we won't get into for competitive reasons is where our rates are. But certainly, certain segments of our business, rates have gotten tighter, more competitive and some actually have gotten wider. But we are very excited that we've expanded the vast majority of our ethane contracts into 2041. And as you mentioned and as we've mentioned, we also are very excited about some very far down the road negotiations that we believe are very close to coming to fruition on not only additional ethane, but certainly significant ethane expansion but also additional propane.

So what our commercial teams do, they extract as much value as they can that the market will provide. We're very excited about the rates that we did roll over for 10 years. And we also have really good rates of return on -- will have good rates of return on the next projects that we announced.

That makes sense. And you decided at the beginning of this year not to move forward with Lake Charles, but I think you were open to kind of potential partners. Have the recent events in Iran driven any new interest from potential partners?

Listen, this is Tom Long. And I think the short answer to that is no. There's been some light interest, some inbounds. But overall, there's not been anything of any meaningful discussions on any type partners on that. So we're still open, very much open to looking at ideas for Lake Charles, especially with us providing all the upstream benefits of the connectivity to our pipes and everything else. So we're open for that, but I wouldn't guide you to anything -- any meaningful discussions.

We have the next question from the line of Keith Stanley from Wolfe Research.

I wanted to follow up on what you're looking at for the next potential ethane export project. Could this be something similar in size to what you did with the satellite JV, time line and what customers you're targeting on that, if it's Chinese customers or others?

Yes. This is Mackie again, and Adam may want to follow up on this. But yes, once again, I won't, of course, get into specifics on companies or countries, but it is fair to say we are chasing the ethane markets all over the world. Certainly, there are some still in China, of course, but there's also others in other countries that are building crackers that we are pursuing and feel confident we will -- that will be a part of our next expansion. So I'll put it this way, there's probably between 500,000 to 750,000 barrels of ethane interest around the world on new crackers. And so wherever the best margins are, the best volumes are and the best customers for our business, those are the companies we're chasing.

Okay. So it sounds like it could be as big as satellite-type sizing based on that demand, I would think.

Or yes, or larger.

Got it. Second question, so it's good to see the company have 2 straight quarters of gas pipeline projects that are meaningful with Springerville. As you look forward, are there any interstate gas pipes in particular that you'd highlight as seeing potentially meaningful growth opportunities or demand increases? Just what stands out on the interstate side in your system for sizable investments?

This is Mackie again. As we've announced and as was discussed already, we're very excited about FGT and those expansions. It seems like that's never ending with the volume growth in the Southeast. It's just incredible how that pipeline just keeps needing to be expanded. So who knows? I wouldn't be surprised that by the end of this year, we'll be looking at expanding that pipeline again. And so when you say that, you go, where is all the gas coming from? So there's definitely a need to move more gas from West to East. As everybody knows, we had an open season for our South Mississippi project, and we have not to FID by any means on that.

However, we made a lot of headway that pipeline connects kind of the Perryville area to several pipelines, but predominantly to FGT. So that would be a good supply source for that. That's a very viable project that we hope to get to FID over the coming months. And then if you look throughout the country, there's opportunities. But right now, we're focusing on bringing online the pipelines that we're building, Hugh Brinson DSW and fully filling up all of our other pipeline assets, which we've been able to do throughout the country. So that's kind of where our vision is right now on the interstate pipeline expansion opportunities.

We have the next question from the line of Jackie Koletas from Goldman Sachs.

I first wanted to focus on just the NGL business. You noted record volumes across the system. But how are you thinking about your NGL pipeline recontracting, particularly in the context of deeper or gassier benches in the Permian?

Yes. We -- very competitive. A lot of NGL pipelines have been announced. As we always say, we don't really worry about what others announced. We worry about ourselves with us bringing on more cryos and also chasing NGL liquids from third-party cryos. Our team has been very aggressive. We are very optimistic over the coming year of replacing volumes that may be coming off over the next year or 2. We also are adding a little bit of capacity. We've got 90,000 a day that we'll have ramped up by next year. And we are highly confident over the next year or so that we will -- similar to our other NGL businesses, frac, export, et cetera, that we will have the vast majority of that locked in at least into the 2030s, early 2030s. But there are a lot of barrels, a lot of plants being built, and we're very optimistic about keeping our NGL pipeline full.

Jackie, just to piggyback on Mackie's comments, too, the one thing you have to remember with our franchise as well is all of these plants that we're building are going to have significant NGL supplies. And so we have the luxury of generating a lot of our own growth on these pipelines. And that really allows us to be able to have a great line of sight into keeping our pipelines full and keeping them full at reasonable rates.

Got it. Understood. And then just wanted to touch on the Bayou Bridge expansion project. I mean what is driving the customer demand there? I mean is part of that driven by exports specifically? And if so, is there an ability for additional expansion opportunities for crude to move that more out east from here?

Yes. This is Adam. So Bayou Bridge is really just driven by increased baseload customer demand. So that pipe has continued over the last several years to operate at or near capacity, and we've seen strong results from it, and we're able to go out and enter into recontracting with one of our original shippers on that to deliver to their refinery. And so we were able to not only extend the terms out, but to increase the volume and underpin expansion. We've also seen more demand further east into the St. James market. So all those things are really leading to the increased demand on Bayou Bridge, really not so much related to anything from exports there.

We have the next question from the line of Julien Smith from Jefferies.

This is Rob Mosca on for Julien. Just wondering if the disruption that you've seen in the international LPG markets in the wake of what's happening in Iran, has that maybe caused you to revisit projects such as the Panamanian LPG pipeline. Wondering how that factors into what you guys could potentially do on the LPG side.

This is Mackie again. Yes, same thing, same common statement we all keep making. We are incredibly well positioned to deliver products, ethane, propane, butane for the international market, and there's no question that's going to continue to grow for many years to come. Estimations are for the next 15 to 20 years, those product demand will grow by 3% to 5%. So we're very well situated. And the Panama Canal project, if it comes to fruition, we think is a game changer. We hope we're part of that project.

We believe we will be, and it will be the go-to place for much of the world instead of worrying about all the dynamics, getting through all the canals and all the straits and all the issues dealing with getting products to the markets. These -- so many of these companies and countries will just cross the Pacific, load up and go back, no waiting time, no nothing. And then we have more than enough product ourselves alone, plus with the rest of this country to keep that project once it comes online fully loaded. So we hope that gets to the end zone. We think it will. We think it will be a huge benefit to our country, a huge benefit to Panama and more importantly, a huge benefit to the world.

Great. Appreciate it, Mackie. And maybe sticking with the LPG theme. It seems like we're seeing a lot of positive data points around in-basin demand to the Northeast. Wondering how that could set up your franchise, your NGL and export franchise in the Northeast for expansions and what potential tailwind you could experience there if you do start to see some more gas growth in the Marcellus, Utica?

Yes. We keep saying this, how well positioned we are, but my goodness, there's nobody even close to as well positioned as we are with the 3 pipelines that we have to move products from West to East in the Northeast. Our continued ability to expand our capabilities -- for example, we're adding 20,000 a day of ethane, not huge, but it's definitely an expansion. We have the capability of adding a lot more capacity at Marcus Hook. And our teams are focused right now on the contracts that in over the next 4 or 5 years of extending those out. We're excited about how those are going.

So that's going to continue to be a very great asset and revenue generation segment of our business, and we have a great team to maximize on that. And yes, I don't know what the question is. We've seen -- we talked about this before this call. We've seen the Northeast, Marcellus, Utica kind of hang around 33, 34, 35 Bcf forever. It has the potential to grow significantly. However, you got to make sure you have enough pipeline infrastructure. MVP, Rover helped that a lot. But we don't know where ultimately that will go, but we know we're very well positioned to maintain the business we have today and to grow it as needed as that basin expands.

We have the next question from the line of Manav Gupta from UBS.

Congrats on a good quarter. Just wanted to ask you about the 2 FGT projects. The prospects over there, any gating items before you can move to FID and the kind of benefits that those 2 projects offer? And the second follow-up question is, on the call, you talked about getting more Canadian light sweet crude into the U.S. to an open season that's going on. Can you talk a little bit more about that also?

You bet. This is Mackie. I'm going to start first, and Adam will finish with the second. I believe you said FGT. So yes, that project has no contingency. We're already out there ordering compressors, ordering pipe. We will be completing that over the next several years, and we're very excited about that. As far as the Florida project, South or South Florida project, we're bound to move forward. The customers do have some options that we're waiting for them to exercise their options, but there's about a 90-plus percent chance they will, and that will reach full FID, but there are 30, 60 days left for them to make some elections that we've got to wait them to make before we ultimately bring that project to full FID.

This is Adam. So on the second part of your question as it relates to the Canadian light on DAPL. Yes, we continue to be really excited about that project and reaching FID later this year. We have -- Enbridge has launched the open season, and we're in that process right now, but kind of continued theme on this call of the world needing more North American energy, surety of supply. Even before the Iran conflict, Canadian volumes were expected to see significant growth between now and the end of the decade. And what we know is that MLO2 is the right project at the right time and the only project that's out there in the market that can provide the needed egress for that growth. And that was growth before the war started, which subsequently, we expect there to be more. So we're really excited about MLO2 and look forward to having more to talk about that later this year.

Completely agree on MLO2.

Ladies and gentlemen, that was the last question. I would now like to turn the conference over back to Mr. Tom Long for any closing remarks.

Listen, thank you. We really appreciate all of you joining. You can see we've got a lot of great projects to talk about. We've got a great outlook, not just the quarter we just reported here, but for a long time to come. But as you continue to look at these projects and how they're supported by good long-term contracts with a good mix of not just supply side, but on the demand side with a lot of the discussion today around contracts that go out more than 20 years. You can see why we remain so optimistic and so excited about what we're doing. But thank all of you for joining us today, and we definitely look forward to any follow-up questions you have and having discussions with you.

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

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.

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.

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

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?

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.

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?

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.

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.

The next question comes from Gabe Moreen with Mizuho.

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?

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.

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?

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.

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

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?

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.

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?

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.

The next question comes from Keith Stanley with Wolfe Research.

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?

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.

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?

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.

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

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?

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.

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.

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.

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.

The next question comes from John Mackay with Goldman Sachs.

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?

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.

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

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.

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?

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.

The next question comes from Manav Gupta with UBS.

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?

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.

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?

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.

The next question comes from Michael Blum with Wells Fargo.

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.

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.

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?

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.

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

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?

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?

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.

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?

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.

The next question comes from Zach Van Everen with TPH.

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?

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.

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?

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.

The next question comes from Jason Gabelman with TD Cowen.

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?

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.

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.

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.

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.

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.

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

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.

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

Good day, and welcome to the Energy Transfer Q3 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Tom Long. Please go ahead.

Thank you, operator, and good afternoon, everyone, and welcome to the Energy Transfer Third Quarter 2025 Earnings Call. I'm also joined today by Mackie McCrea and several other members of our senior management team who are here to help answer your questions after we get through the prepared remarks.

Hopefully, you saw the press release we issued earlier this afternoon. As a reminder, our earnings release contains 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-Q for the quarter ended September 30, 2025, which we expect to file tomorrow, Thursday, November 6. 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 off today with the financial results for the third quarter of 2025. We generated adjusted EBITDA of $3.84 billion compared to $3.96 billion for the third quarter of last year. Excluding several nonrecurring items, adjusted EBITDA was flat year-over-year. We saw several volume records during the quarter, including midstream gathering, NGL transportation, NGL and refined products terminal volumes and NGL export volumes. We also saw strong volumes through our natural gas interstate and intrastate pipelines.

Year-to-date, we generated adjusted EBITDA of $11.8 billion compared to $11.6 billion for the same period in 2024. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $1.9 billion. And for the first 9 months of 2025, we spent approximately $3.1 billion on organic growth capital, primarily in the NGL and refined products, midstream and intrastate segments, excluding SUN and USA Compression CapEx.

Now turning to the results by segment for the third quarter, and we'll start off with the NGL and refined products. Adjusted EBITDA was $1.1 billion compared to $1 billion for the third quarter of last year. We saw higher throughput across our Gulf Coast and Mariner East pipeline operations, as well as through our terminals. For midstream, adjusted EBITDA was $751 million compared to $816 million for the third quarter of 2024.

Results for the third quarter of 2024 included $70 million in proceeds from a onetime business interruption claim that was recognized in the third quarter of 2024. Absent this claim, midstream results would have been up compared to the third quarter of last year due to higher volumes in the Permian Basin, which were up 17% as a result of processing plant upgrades and new plants placed into service, as well as the addition of the WTG assets in July 2024. This growth was partially offset by lower gathering volumes in the dry gas areas.

For the crude oil segment, adjusted EBITDA was $746 million compared to $768 million for the third quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems, including the Permian joint venture with SUN. These were offset by lower transportation revenues, primarily on the Bakken pipeline, as well as on Bayou Bridge, where we saw greater impacts related to some refinery turnarounds in Louisiana, which have since been completed, and volumes have returned to normal levels.

In our interstate natural gas segment, adjusted EBITDA was $431 million compared to $460 million for the third quarter of 2024. Results for the quarter included a $43 million increase related to the resolution of a prior period ad valorem tax obligation on our Rover system. Excluding this accrual, interstate results would have been up compared to the third quarter of last year due to higher demand on several of our interstate pipeline systems.

And for our intrastate natural gas segment, adjusted EBITDA was $230 million compared to $329 million in the third quarter of last year. During the quarter, we saw increased volumes across our Texas intrastate pipeline system due to third-party volume growth. This was offset by reduced pipeline optimization, primarily as a result of our continued shift to more long-term third-party contracts, which are expected to provide more stable revenues at good rates over the next 10-plus years.

Now looking at organic growth capital guidance. We now expect to spend approximately $4.6 billion on organic growth capital projects in 2025 compared to our previous guidance of $5 billion. This is a result of project forecast reductions as well as spending deferrals into 2026. Looking ahead to 2026, we expect growth capital to be approximately $5 billion, the majority of which will be invested in our natural gas segments.

We continue to expect our growth project backlog to generate mid-teen returns. The majority of the earnings growth associated with the Flexport Permian processing, NGL transport and Hugh Brinson Pipeline Expansion Project is expected in 2026 and 2027, promoting strong growth in the coming years. Beyond these projects, we also have a significant backlog of opportunities which support continued growth.

Taking a closer look at some of our recently approved and currently underway projects. We continue to see significant demand for our services on the natural gas side of our business, which is expected to support growing demand for gas-fired power plants, data centers, and industrial and manufacturing.

First, looking at our Desert Southwest pipeline project, which we announced last quarter. This strategic expansion of our Transwestern Pipeline will enhance system reliability and provide new and existing markets in Arizona and New Mexico with access to low-cost, reliable Permian Basin natural gas. We recently completed an open season, and the 1.5 Bcf per day project is now fully contracted under long-term commitments with investment-grade counterparties with a term of 25 years. This includes a 400,000 MMBtu per day contract with a new demand source along the pipeline route. In addition, since the launch of the open season, we have received significantly more interest in current planned capacity, and we are evaluating options around a potential increase in capacity.

We also recently entered into commitments with U.S. [ pipe mills ] to lock in the majority of space and delivery for [ pipe ] in the fourth quarter of 2027 at favorable prices, and we expect to have 100% locked up very soon. Since the day we announced this project, our teams have been actively engaging with elected officials, county leadership and associated communities along the route to communicate project information and updates. To date, we have engaged with over 175 stakeholders who have interest in or are involved in this project. Our discussions have been very positive, as these stakeholders are pleased about the economic benefits expected and also realize the critical need for a substantial supply of gas to help address the significant demand growth in Arizona and the Mexico markets by providing access to reliable, affordable electricity.

Next, we continue to expect Phase 1 of our Hugh Brinson Pipeline to be placed into service no later than the fourth quarter of 2026. As of today, 100% of the right of way has been acquired for the proposed route. Over 85% of the pipe has been delivered to our pipe yards, and construction is underway on all 5 spreads of Phase 1 of the project. In addition, last quarter, we announced Phase 2 of the project, which will include additional compression. 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 Hugh Brinson pipeline will provide significant optionality by connecting shippers to our vast natural gas pipeline network, as well as providing access to the majority of gas utilities in Texas and to [ Ever Major ] trading hub in Texas. Additionally, our existing customers have the option to increase their volume commitments, and we will expand the system to meet those commitments in accordance with those agreements, if exercised. At this point, over 90% of our 3.8 million MMBtus per day of Texas cross haul capacity is sold out with demand charges through 2036, with the majority of this volume extending out through the remainder of the decade. This includes Hugh Brinson and all the other pipeline flows from the Permian Basin to markets in the East.

We have also sold capacity from East to West on the same systems, which will add significant revenue to our pipeline assets without additional capital. We are constantly evaluating whether our pipelines can generate more revenue by transporting a different product. In numerous instances, we have converted systems to different products, which have generated significantly more revenue once they are converted. Although we are highly confident that we can keep our NGL pipelines out of the Permian Basin at or near capacity, we are considering converting 1 of our NGL pipelines to natural gas service. Considering the contracts we have already consummated, as well as the numerous transactions we are negotiating, we believe we may have the opportunities to significantly increase the value of that capacity by converting it from natural gas liquids to natural gas transportation service.

In August, we also approved the 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. And we expect to place the new cavern in service in late 2028. This expansion will increase our equity gas storage capabilities to serve growing demand in the heart of our extensive intrastate natural gas pipeline network and will further strengthen the reliability of our systems, as well as provide the opportunity to benefit from pricing volatility. We are well positioned to meet the future growth, and we have the ability to develop at least 15 Bcf of additional storage capacity at Bethel.

Now for a brief update around the recent natural gas opportunities for new power plant and data center development. As a reminder, on our last call, we announced that we had signed a deal to provide natural gas supply to a major hyperscaler in Texas. Since then, we have added to that agreement and are now able to disclose that we have entered into multiple agreements with Oracle to supply natural gas to 3 U.S. data centers, 2 of which are in Texas.

Under the terms of these long-term agreements, Energy Transfer will deliver approximately 900,000 Mcf per day of natural gas. Supply for these agreements is expected to be sourced from our extensive intrastate pipeline network. And construction of a new pipeline lateral from Hugh Brinson and our North Texas pipeline is underway. First flow is expected to occur by the end of the year, with final completion to follow in mid-2026.

We have also entered into a 10-year agreement with Fermi America to provide a pipeline interconnection and exclusively provide initial gas supply of approximately 300,000 MMBtus per day to Fermi's hypergrid campus located outside of Amarillo, Texas, subject to Fermi's election. Energy Transfer has entered into several of these types of exclusivity agreements with data center and power plant customers, reflecting more than 1 Bcf of additional supply should these projects move forward.

In addition, we recently entered into a 20-year binding agreement with Entergy Louisiana to provide 250,000 MMBtus per day of firm transportation service to fuel their facilities in Richland Parish, Louisiana, subject to limited conditions precedent. The agreement would begin in December 2028 and includes an option for Entergy to expand the capacity in the future. Within the last year, we have contracted over 6 Bcf per day of pipeline capacity with demand-pull customers. These contracts have a weighted average life of over 18 years and are expected to generate more than $25 billion of revenue from firm transportation fees. This includes volumes from end users, data centers and utilities off of Desert Southwest, Hugh Brinson and other of our natural gas directed projects.

Also, our interstate power plant and data center team is working on multiple transactions in a number of states other than Texas and Louisiana which have a high likelihood of reaching FID. These opportunities continue to show how extensive our interstate pipeline network is throughout the country and how fortunate we are to have so many of them near our pipeline assets. In addition to the gas-fired power plants and associated data center opportunities, we also continue to negotiate with industrial, manufacturing and utility customers needing our gas storage and transportation services. Our team continues to do an excellent job of identifying the most likely opportunities, and we remain in advanced discussions with several other facilities in close proximity to our footprint. Lastly, construction of 8 10-megawatt natural gas-fired electric generation facilities continue, and we are currently commissioning the third facility at our Grey Wolf processing plant.

Now looking at the Permian processing expansions. As a reminder, both the Lenorah II and Badger's 200 million cubic foot per day processing plants are in service. The Lenorah II plant is currently running at full capacity, and the Badger plant continues to ramp up. As a result of our recent processing plant optimization and expansion projects, our processed volumes in the Permian Basin, as well as [ Y-grade ] transportation throughput from the Permian, reached new records during the quarter.

In addition, we continue to expect our Mustang Draw plant to be in service in the second quarter of 2026. We also recently approved the construction of Mustang Draw II, which will have a capacity of 250 million cubic foot per day and is supported by continued growth from existing customers. Mustang Draw II is expected to be in service in the fourth quarter of 2026 and is expected to cost approximately $260 million, including spend related to additional gathering and downstream pipeline infrastructure. It will add additional revenue to our downstream assets as well.

At our Nederland terminal, our Flexport NGL Export Expansion Project was previously placed into ethane and propane service, and volumes are expected to continue to ramp up throughout the remainder of 2025. In addition, the facility is now ready for ethylene export service. We expect to have over 95% of all LPG export capacity at Nederland contracted through the end of this decade.

In our crude segment, an expansion is underway at our Price River Terminal in Wellington, Utah. This expansion, which is backed by an agreement with FourPoint Resources, is expected to double the terminal's export capacity and enhance its deliverability of American Premium Uinta oil to markets throughout the Lower 48. The expansion includes new railcar loading facilities, a new heated storage tank with approximately 120,000 barrels of capacity and 2 additional 6,000-foot storage unit tracks, which will significantly improve storage capacity at the facility. The project is expected to cost approximately $75 million and is expected to be in service in the fourth quarter of 2026.

In September, Energy Transfer, along with Enbridge, completed a successful open season for the Southern Illinois Connector Project, which resulted in 100,000 barrels per day of contracts for transportation of Canadian crude oil to Nederland from both Flanagan and Hardisty. This project will connect Enbridge's pipeline near Wood River to Energy Transfers assets in [ Patoka ], Illinois to support the delivery of Canadian crude oil to the U.S. refineries, further strengthening market connectivity and value for all our stakeholders.

Separately, Energy Transfer is working with Enbridge to provide capacity for approximately 250,000 barrels per day of Canadian crude oil through our Dakota Access pipeline. This project would provide much needed capacity for oil out of Canada and would be a significant part of the steady volume throughput on Dakota Access for many years to come. We have taken FID on the Southern Illinois Connector Project and expect to take FID on the other project by mid-2026. We are very excited about both projects, which would fill available and additional capacity on our Dakota Access and [ ETCOP ] pipelines, and we look forward to providing additional details in the future.

Turning to Lake Charles LNG. We are in advanced discussions with MidOcean Energy related to its participation as a 30% equity owner of Lake Charles LNG with a commensurate percentage of LNG offtake. We're in discussions with other parties for the remaining equity we intend to sell in order to reduce Energy Transfer's equity interest to 20%.

We are also in the process of converting nonbinding heads of agreement with several offtake customers to binding agreements with the remaining volume of offtake needed for positive FID. FID on the project will be dependent upon bringing these items to the finish line. We continue to be extremely focused on capital discipline. The process we are going through during the development of our LNG project highlights this focus. Our projects need to meet certain risk/return criteria, and we are not there yet on LNG.

Now turning to guidance. We expect to be slightly below the lower end of the guidance range of $16.1 billion to $16.5 billion. Looking ahead, Energy Transfer is one of the best positioned companies in the industry to help meet the substantial growth in demand for energy sources over the next several years. We are leveraging our strong relationships to develop new projects, backed by high-quality counterparties on both the supply and demand side, and we see growth opportunities across all aspects of our business.

When combined with our existing natural gas pipeline network, our Hugh Brinson, Desert Southwest and Bethel storage projects further establish us as the premier option for customers seeking reliable natural gas solutions to support their power plant and data center growth plans. Our significant processing capacity expansion in the Permian Basin will help feed our downstream pipeline network. We are continuing to expand our NGL business in the United States to help meet growing international demand, and we continue to expand our crude oil pipeline network with strategic projects that will help fill available and additional capacity on our existing pipelines.

In short, we have an extensive backlog of growth projects that are coming online over the next several years, and we continue to be extremely focused on capital discipline. These projects are highly contracted under long-term agreements, many of which are demand pull in nature, and they are expected to generate significant revenue, providing strong returns and considerable earnings growth over the next decade or more.

That concludes our prepared remarks. Operator, let's open the line up for our first question.

[Operator Instructions] The first question comes from Keith Stanley with Wolfe Research.

First, I just wanted to clarify on the guidance for the year. So saying you'll be a little bit below the low end of the range for 2025, does that include SUN's acquisition of Parkland? Or is that still stripped out when you're making that statement?

This is Dylan. For the guidance, we have not included Parkland in there. So we're saying without Parkland, we expect to be slightly below the initial [ guide ].

Okay. Great. And then picking up on Lake Charles, where you left off there. Can you give us more detail on -- I guess, realizing you guys are showing capital discipline, just how many more contracts you need at this point to firm up? And I guess, where you are timing-wise in the sell-down process to get to an FID decision?

Yes, Keith, this is Mackie. Let me step back real quick. We worked on Lake Charles for a lot of years. We've had different partners. We've gone through the pandemic. We've gone through DOE positive, LNG positive, Ukraine. Everything kind of ebbs and flows, and Tom and Amy and his team have done a great job of getting markets in difficult times, especially when we're competing against companies that's all they do is LNG and they're willing to go to FID without having sufficient contracts to provide guaranteed rates of return.

So where we sit is -- and we've said this all along, Tom and I -- the only way we get to the end zone with LNG is to check all the boxes. And the major boxes are our EPC contract. We feel great about Raj and Rob and the team that work very well with [ KBR and Technip ] to get a good price there and add contingency and get rates of return that work for us. And then we've spent a great deal of time getting the markets to where they need to be. We're very close to that 15 million, 15.5 million tons. Some of those are still HOAs we've got to convert to SPAs that we expect to do by the end of the year.

But the big box -- and Tom has already hit on this -- we really are focused with all the opportunities we have on our financial discipline. So we're very stringent about this one in regards to we're going to keep 20% of the equity in this, and we've got to have 80% of the other partners that are going to ride with us, good or bad, whether it's -- comes in under or over at the end of the day. So a specific number of contracts, and we've got a whole handful of equity players. We have -- it's amazing, the international market of how bad they want this project to go. It's one of the most attractive projects still not at FID, but we've got a lot of work to do.

We -- time is not working against us. We'll have to go in and renew the EPC contract before too long. So we're hoping that these equity partners will step up by the end of the year and get us to where we want on kind of the risk profile and the participation we want in this project. So we're going to keep our heads down, we'll see over the next couple of months how things turn out, and we're pushing hard to get there, but we've got a ways to go.

The next question comes from Jeremy Tonet with JPMorgan.

This is [ Eli ] on for Jeremy. Just wanted to start on some of the recent data center deals you guys have signed. Trying to get a sense of the financial impact going forward. Just given the size of the partnership, I understand the orders of magnitude that it could have to the business, if you can provide some commentary there?

You bet. I think probably 7 or 8 of us, we'd love to talk about this. It's so exciting. We talk about every time we get on these calls. A year ago, when we announced Hugh Brinson, we didn't even know what a data center was. And we kicked it off a little less than 1.5 Bcf, and then data centers kicked in, and it's really been an impetus between that pipeline. Also, Desert Southwest had a lot to do with data centers. And then it just opened up the door for so many opportunities we're so excited about.

The unique nature of these data centers, especially the hyperscalers are very confidential. So unlike a lot of our business, we can't really talk about it. I can't really get out there and get out in front of it. We were pleased to have the ability to disclose what we disclosed for this earnings call, believe me. And Tom said in the opening statements, we have so many of these we're chasing. A lot of them are high probability to get there.

As far as how many we've done so far than what we've disclosed which is on demand pull, a lot of that $25 billion is toward data centers. And I'll say 1 more thing, too, around data centers. Besides the fact that so many of them are in such close proximity to our pipelines, the Hugh Brinson pipeline, I believe -- and I don't think I've said this to a lot of our folks here is that I think it will be the most profitable asset we've ever built. And the reason for that is it's kind of the main artery connecting the Permian Basin with the rest of the world, the Southeast, East and rest of Texas, Gulf Coast and all that.

And so not only have we sold out to this point, 2.2, we have data centers that have options over the next few quarters to exercise the right to create 800,000 more of capacity. So we'll be doing some more looping of Hugh Brinson. And in addition to that, we've sold a material amount of capacity, significant revenues from an East to West standpoint, which means a backhaul with no additional capital. And I think our data -- Adam is sitting here with me, he leads our data center group in Texas. And we couldn't be more upbeat about where we sit today through data centers throughout the country, but especially in Texas because of our ability to perform and provide reliable gas to all these data centers and because of our close proximity to where these are being built and our ability to source from Waha, Maypearl, Katy, heck, South Texas, Carthage. You can even leave the state and bring gas into some of these data centers.

So it's something we'll be able to talk more and more about as these confidentiality issues go away as we're able to visit more. We're very excited about the future, and it's hard to over-exaggerate what these data centers and power plants associated with those and power plants unassociated with those for a grid to deliver electricity into the grid. So a very positive, exciting part of our growth for many years to go.

And then recognize 2026 budgeting is likely ongoing, but just want to think about it at a higher level, the kind of major puts and takes that you guys are looking at, both on the base business and then some of the organic growth projects that you're bringing on, just kind of framing the high-level drivers for performance next year?

This is Dylan. So as we look at next year, I think the biggest piece is really to look at -- we are going to have really the main impact of Flexport coming online. Those contracts kick in basically January 1. And so while we've got a little bit of little bit of spot volumes running here through the third and fourth quarter this year, we're going to get the full impact of Flexport coming online.

Permian. Permian plants continue to fill the plants. We've got new plants that we're constructing right now, so we'll see the continued growth out of that. With all those plants, remember, we're sending those liquids down our NGL lines into our NGL and fractionators as well. So that will continue to be growth. We'll have frac line coming on next year as well. And so those are the main pieces there. And then Hugh Brinson will come online at the end of the year next year. And so just wait to see based on timing, how much impact that will have as well.

The next question comes from the line of Theresa Chen at Barclays.

I want to ask about the consideration of converting 1 of your NGL pipes to natural gas service in the Permian. Would you be able to provide any additional details related to that at this point? Which pipeline do you have in mind for this? I imagine something directed to the Gulf Coast? What would be the cost and related economics of doing something like this?

Yes, Theresa, this is Mackie again. Let me give a quick little history. So you'll probably know most on the call that we are constantly looking at every one of our assets. And if assets are underutilized and could be put into a different service, we do that. And we have a [ record ] of doing that. Dakota Access would not have been a project without our ability to convert our 30-inch trunkline from natural gas to oil. It was very beneficial to the North Dakota producers to get a good rate down to the Gulf Coast. We converted a TW line as a natural gas interstate pipeline and natural gas liquids, which has been instrumental about getting a lot of liquids out of the Delaware Basin into our pipeline network. And also, our [ J.C. Nolan ], it was a liquid line that we converted to diesel and are flowing diesel from the refineries in the Gulf Coast to West Texas.

So it's something we're constantly looking at. And what we run into on the NGL front is that we have some tiers, some contracts, cliffs over the end of this decade that is kind of approaching. So as we negotiate to extend and or fill that up, what we've started to recognize is there's been a lot of announcements. One of our competitors several months ago announced a large [ miner ] NGL line. That was just the most recent pipeline announcement for an NGL line. We're scratching our head. How in the heck in this environment, at the rates these folks are quoting to producers, how they can build these assets and get any kind of reasonable rate of return.

So what it's causing us to look at is -- we have 3 NGL pipelines out of the Permian Basin. Does it make sense to continue those NGL service in May? We're in negotiations with over 300,000 barrels right now. But we're looking at very closely as we continue to negotiate. As the fees get more and more tight and more competitive, it just doesn't make sense. So you correlate that with the success Adam and his team have had on these data centers and you start putting numbers to it, if these options are exercised over the next few quarters, we're going to be looping [ pipe ]. We're going to have [ to be required ] to loop Hugh Brinson, make it a bigger project.

We could forgo between $800 million and $1 billion. And if you look at the rates that we'll have to move that gas on the anticipated volumes that will recontract up at these much reduced rates, some of the scenarios show twice the revenue with natural gas as what we might see with NGL. So this is not something we're making a decision on today. But as we always look at and analyze, how do we make the most money we possibly can for our unitholders with the assets we have, and we are certainly, seriously looking at this conversion.

Understood. And on that same line of thinking as it relates to capital efficiency, your agreements with Enbridge on the crude side and moving WCS through [ DAPL ] and [ ETCOP ] to Nederland, it seems like that time line would line up nicely with [ DAPL's ] recontracting in the 2027 time frame. And considering the narrowing of Bakken differentials over time, certainly, a new source of barrel is welcome.

From an earnings perspective, are these connections backfilling volumes and maintaining earnings at the level that they are versus facing a contract roll off? Or would you expect earnings growth across your crude assets as these projects come online?

This is Mackie again. I think we probably used the word exciting, excitement too much. But we're very excited about what's going on in there and teaming up with Enbridge because you're right. It's almost like you've got somebody in our office. You're right. I mean, we've seen volumes level off. If you talk to the majority of the largest producers in the Bakken, they're not talking growth anymore. They're talking kind of flatline. So as these cliffs fall off of some of these contracts, the timing with what we're doing with Enbridge could not be better.

We just announced today that we've got FID on 100,000 barrels of heavy that we'll deliver into our southern end of our Dakota Access, which we call [ ETCOP ]. And even more exciting is the need for Canadian barrels to find better markets, and the best markets for Canadian barrels or U.S. refineries. So we're very pleased with where we sit with Enbridge. We -- we -- they are going through a process with the Canadian producers. It's going to take several months. I'm not sure I've heard -- we've heard any protest, exceptions or anything. Everybody is fully behind this. We kind of think of this as the first phase, that's 250,000 a day.

So to your answer to the question, it fits in perfectly. Our first priority will be to make sure that we give the opportunity for all the producers in North Dakota to sign up for whatever term they want to make sure there's capacity on Dakota Access for their pipeline. That's our first priority. Our second one is keeping our pipeline full. We have the ability to move 750,000 barrels a day. We're 500, 550 today, so we can move a lot of the barrels from Enbridge without much capital, but we also think this may be just a stepping stone of what we may be able to accomplish with Enbridge out of North Dakota.

But anyway, on the first 250 that we're parlaying very well with any declines or any cliff that we have on existing with the timing of these first 250,000. And then like I said, we think there's also some upside. So as Tom said in his remarks earlier, we are so excited about the timing of this and how it's going to keep Dakota Access full for a long time because these are 15-year agreements that we'll be working on with the Canadian producers. It will take us into the [ 2040s ].

The next question comes from the line of Spiro Dounis with Citi.

I want to start with the growth backlog more broadly. Curious, how you're thinking about the total opportunity set for growth, maybe beyond the sanctioned projects and a lot of the ones you've talked about today? Some of your peers have started to quantify these opportunities with multibillion-dollar backlogs. And so curious if that's a number you'd be sort of willing to share? Or maybe even another way to think about it, how do you think about a new run rate for CapEx in this environment?

Yes. Listen, I'll go ahead and start off with that. This is Tom. We have put out the $5 billion for next year. Obviously, as we get into early next year and year-end, we'll keep that number updated for you. So you can see we've got -- we do have a great backlog of very good, high-returning projects. And if you start trying to look out further than that, I don't know that we can really give you a lot of guidance there. But you can see just from what we're already talking about -- I'm not trying to guide you toward the '26 number continuous, but you can see we continue to have a lot of opportunities, and we've got a great team that's out there chasing a lot of these.

So in fairness, at this stage, don't really have a -- probably a number for you there, but it's going to be a strong number. And they're going to be good returning projects, and we're going to make sure that we have the appropriate risk on them too as we venture off into these. So...

Got it. I appreciate it, that one. Second one, maybe just going to Desert Southwest. You mentioned seeing additional interest there. Could you maybe just remind us again how you're thinking about upsizing that pipeline, what diameter you're looking at now? And you also mentioned, I think it was 400,000 [ dekatherms ] a day of demand source along the route. Can you just expand a little bit more on that?

Yes, this is Mackie again. Yes, Beth and her team did a fantastic job. We kind of -- in a lot of these cases, on these projects started way behind. And it took a while to get there, but we were very pleased to announce that. We just -- we've taken trips to Washington. We've been to both states along the way, and the project is very highly thought of from a political standpoint and from an economic standpoint. So huge upside there. We did complete the overseas on as we have said, there's at least a Bcf above what we've already sold out above the 1.5 Bcf. So we're in -- a lot of work to figure out. Some of those involve some laterals off of [ DSW ]. So we've got some work to do.

But we certainly have the capability of increasing it by at least 0.5 Bcf, possibly up to 1 Bcf, we'll be making those decisions over the next 5 or 6 weeks. We've locked in steel prices for a majority of that project, and we up until the middle of December, we have the flexibility to go from 42 to 48 or any combination thereof. So we sit in a really good spot on where we've already locked in prices, and we'll see how it plays out.

As part of the 400,000, that kind of falls under that unique nature of confidentiality. We can say a whole lot more on that. But that project and others similar to that, we are chasing, and I would say we're pretty confident that we will expand it higher than 1.5 Bcf, but not sure if we'll get to 2.5, but we'll see how the next 6 weeks play out before we have to make a decision on pipe size.

Next question comes from Jean Ann with Bank of America.

Congrats on all the data center deals. I know you get asked this frequently, but you've been so active with the hyperscalers. I think you said earlier this year that Energy Transfer place in the story is primarily gas supply. But what keeps you from wanting to go into the power generation itself in a bigger way?

This is Mackie again. I think we're all anxious to answer this. Because we like good rates of return on our projects. And we just -- unless we've missed the boat on that, the opportunities that we've seen are low double, if not high single digit, it just doesn't fit. I mean, we'd love to team up with the folks that are generating those projects and provide all the gas they want. Not saying that we never will participate in that, but we'd have to see a lot better rate of return than what we've seen in the projects we're aware of.

That's very clear. And then as a follow-up, earlier this year, you FID-ed the Bethel gas storage expansion. Are gas storage rates high enough today to drive material other brownfield storage expansions in the U.S.? Or is Bethel kind of a unique case? And do you kind of see more upside on gas storage rates as LNG starts up in the next few years? What inning do you feel like we're in, in those rising?

I'll go again. Here we go again, exciting. Storage is another huge area for us. We have about 233 Bcf of storage. We're expanding Bethel by another 6 Bcf, which is about 240 Bcf. The majority of that, probably 190 Bcf is in Oklahoma, Louisiana, Texas, very well positioned, tied to our large [ under ] pipeline. And with the absolute necessity of reliable gas supplies to the -- all these data centers, it's imperative that we have the ability through our [ big inch diner pipe to ] deliver and more importantly, deliver when we have freeze offs in Oklahoma or freeze-offs in the Permian Basin or other areas.

So we believe that the value of storage is going to skyrocket. You think about 30 Bcf of LNG that's going to come online by the end of this decade, early 2020, and you pick a [ Harvey ], you pick a hurricane that spins along the Gulf Coast for days. Yes, there's some storage capability of all these LNG facilities, but there's going to be problems, and it's going to happen. And we're going to be very well positioned.

As far as Bethel, which we had 100 Bcf there. It's in the heart of all of our large diameter systems. It gives us the ability to come out of those systems [ and where ] in Texas, all the major hubs, all the major utilities and as well is going into the interstate markets both at Waha area, our interstates and others and also the Carthage area. So we are very bullish. However, we're not going to go out and just back a bunch of storage. We're very disciplined. It's kind of where we're at now, and all of our capital spending, as we Thomas said several times. And so -- but it doesn't mean that within the next 6 months, we don't kick off another storage to back to another project.

And it's very important to our data center customers. So we have a lot, and we look forward to talking over the next few quarters of a lot of others that we intend to add, but to not only have the capability we have. I just said kind of all these other receipt points, but also in dire times like [ urea ] and tough times, we have the ability to perform unlike anybody else. And storage gives us that backdrop to be able to do that.

The next question comes from Michael Blum with Wells Fargo.

I wanted to go back to the data center deals, you've announced Entergy, [ Berman ], Oracle. Is there a way -- can you provide us any kind of framework for how to think about the capital outlay for each of these data center supply projects and your expected returns? I realize they're all a little bit different, but just like high level or a way to think about that?

Sure. High level, and we've said this before, a lot of the data centers were talking to, very low capital. As I mentioned earlier on Hugh Brinson, we didn't have a data center in our head when we announced that project. And then lo and behold, we go through right by [ Abilene ] with 1 of the largest -- the largest data centers in Texas, we -- all we have to do is lay a lateral, 24-inch lateral kind of a loop system that provides what's going to be needed that location. You look at Franklin Farms in North Louisiana, we're looking at a less than 20 mile lay.

So pretty low capital stuff. Others, depending on where we go, there's some -- a couple of them that are kind of out in the middle of the Panhandle. We look at [ Landt ], those would be capital exclusively for the large capital dollars exclusive for those opportunities. But Michael, I think you said it well, it's all across the board. I mean, it can be embedded in some of our large inter-project that we already have built. It could be embedded in projects that we've announced. And part of that is data center expansions, which is what helped us expand Hugh Brinson was these data center deals that we have done. So it's kind of a combination.

But I'd say a lot of what we're looking at now, especially in Oklahoma and other areas of Texas that we're very close to getting some deals done, much less capital than for the amount of volume that we're talking about. And I have one thing to that. we have some data centers that have secured their electricity supplies somewhere. Renewables, somewhere else. And yet they're willing to pay large demand charges or the ability to instantaneously [ hold ] gas from our system in the event they've got interruptions from their -- so those are very low capital projects that we'd be utilizing. As I mentioned earlier, our storage capabilities, along with our large diameter capabilities to move large volumes quickly to these locations.

Okay. Got it. That makes sense. And then just a clarification on your earlier comments on Lake Charles. I guess the first question is, would you definitely -- do you see this as you're definitely going to get to FID? Or is it really subject to all of those criteria that you laid out earlier? And if you do get to FID, what would you -- what's your latest on when you think timing-wise, you'll get there?

Yes. So let me make this real clear. Yes, we will not proceed with LNG until we have secured 80% of equity partners similar to ourselves. And we've got some work to do that. I mean, we -- getting the contracts done, feel great about that. If you see contract, feel great about that. But the last big, most important box, especially as we're emphasizing this financial discipline that's very important to us.

When you only chase 1 or 2 projects, you don't think about as much. When you're changing billions of dollars in projects, several of which we've already announced, we've got to be careful in stepping out on something like this. And -- we're not an LNG company, like we compete -- we're a pipeline company that has an LNG or a regas facility, converting part of it to LNG. So no, we're not going to get to FID until we have the required amount of equity partners that we need. And we've -- as we've said, we've got our work cut out for us to get that done timely enough to be able to get to FID in relation to our EPC costs that are -- that we have with our EPC contractor today.

The next question comes from Zack Van with TPH.

Maybe going back to Hugh Brinson. Now that Phase 1 is fully contracted and we've seen a few producers come out and indicate they signed up for capacity, can you talk to the breakout of supply push from Waha and demand pull contracts from data centers and other demand sources on that pipe?

Yes. This is Mackie again. I think you said Hugh Brinson, it seems like that we didn't hear the first part of that. But yes, that project started out as demand pull. Then to kind of get to finish line, we had a lot of producer push. And now as we've grown and expanding it, it's pretty much all demand pull. So it's been a pretty balanced combination of those two. But what we do see on the growth on any type of expansion will be a demand pull.

Okay. Perfect. And then I know this might not be your arena and more on the end customers, but it feels like there's a lot of straws going into the Permian for gas between your projects and various other ones through the end of the decade. Have you seen your customers start to talk about actually signing supply deals out of Waha to make sure that gas is there on top of the FT contracts they have with you all?

What a great question. it's interesting because if you don't think we're looking at this closely and doing our own studies in this, but there's been 4 pipelines announced. Depending on rumors, about 1 of those going to a 48-inch, possibly 1 of ours going to 48-inch. We could -- you could see north of 11 or 12 Bcf of new demand projects built out of that, not counting probably 0.5 Bcf to 1 Bcf of data centers that are built in the Permian Basin.

So to answer your question, we are aware of some of the end users have reached out to producers to try to lock some of that up. But the great thing about our assets, our gathering assets, our intrastate, our interstate assets coming out of the Permian Basin, it can do nothing but grow dramatically. It's got to grow between 12% and 15% just to get enough gas to fill the pipes that have been already announced over the next 4.5 years. If I was a market, I would be out locking up production today.

The next question comes from John Mackay with Goldman Sachs.

I appreciate the time. A quick one for me. You have in this slide -- on gas going to the power, you talk about 6 Bs of new deals signed over the past year. If you do some math, it's actually a pretty good margin on those. I'd love to know, how much of that 6 is kind of incremental growth on top of kind of what the business is doing right now? And then, yes, if we were to kind of back into a margin on what -- or a fee and what that's implying, is that a reasonable run rate for what you guys are seeing on some of these incremental power data center deals?

Yes, John, this is Dylan here again. Yes, that's all incremental business that we've signed up that we're not currently doing today. So these are all new demand sources that are in the process of being constructed right now. And so that's all incremental.

Now backing into the fee, yes, that -- that's correct. If you do that math, you will back into a few, but that is made up of a lot of different types of contracts. So I'd be careful on trying to just project that forward on everything. I mean, that's got a good mix of Desert Southwest, some of the setoff in Hugh Brinson and then a couple of Bcf of just other demand growth along our systems or we're building laterals out too. So when you put that all together, yes, you do get to that pretty strong weighted average fee. But like I said, it is made up of those different sources.

Thank you. This will be our last question. It's from the line of Manav Gupta with UBS.

I'll ask only one question. Bloomberg has reported that Energy Secretary [ Wright ], has sent a [ DOT ] proposal to FERC that would limit the regulators review period for data center connections to power grid to 60 days, expediting the process, which can currently take years. I'm just trying to understand if this proposal does go through, could that mean a material acceleration in demand for natural gas to support electric generation? Because, honestly, it's like bring your own electricity right now. So that you might be the only game -- or your pipeline side with only game in town if this proposal actually does go through?

Manav, I think we've not heard that yet, but that would definitely be a big boost to the pipeline business. And being able to move that quickly there would definitely be good for our business.

Okay. Can you elaborate a little bit on the expansion of Price River Terminal? It looks like a very interesting project, an exciting project. And what would be the demand for this expansion?

Yes. Once again, Adam is sitting here next to me. You want a great project. Years ago, we kind of took over that and it was kind of struggling and our team worked very hard to really grow that business, and it's phenomenal what they've done. I would say we've got time to know what percentage locked in of the acreage up there, but it's a significant amount of that acreage is locked into us for many years to come. That's for a lot of refineries that's very valuable, kind of lack the oil that fits what they're looking for.

So not only is that a great project for us as we expand that terminal, but we also see a lot of synergistic downstream, have new possibilities with a lot of those barrels going to St. James and possibly to Nederland. So there's a lot of upside to that project, but stand-alone, that's going to be a really great project for us.

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

Listen, once again, we do thank all of you all, as Mackie answered on several of the questions. Excited, it was the most commonly used word here of how excited we are. And you know that we've -- we've always dreamed of kind of getting to this point right now through our growth here with M&A and organic growth projects. And the reason why you're seeing a lot of this is just because of the massive infrastructure that we've built up and where our assets sit. So that's what's provided the opportunity.

We are going to stay very disciplined on our capital. But these are the kind of projects that are just very high returning projects that are right in our wheelhouse, and we're going to continue to chase them with a great commercial team and the E&C team to build them. And of course, the finance team and the rest of the group, the team to be able to keep everything going. And so you're going to see these opportunities, and we look forward to talking to you more about this capital and about these great projects. Appreciate all of you joining today, and we look forward to the follow-up questions.

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

Good afternoon, and welcome to the Energy Transfer Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Tom Long. Please go ahead.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Second 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 afternoon. As a reminder, our earnings release contains a thorough MD&A that goes through the segment results in detail, and we encourage everyone to take a look at the release, as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities.

As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs, as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended June 30, 2025, which we expect to file tomorrow, Thursday, August 7. 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.

So let's start today by going over our financial results. For the second quarter of 2025, we generated adjusted EBITDA of $3.9 billion compared to $3.8 billion for the second quarter of 2024. We saw several volume records during the quarter, including the midstream gathering, crude transportation, NGL transportation, NGL and refined products terminal and NGL export volumes. We also saw strong volumes through our NGL fractionators, natural gas inter- and intrastate pipelines.

DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2 billion. And for the first 6 months of 2025, we spent approximately $2 billion in organic growth capital, primarily in the NGL and refined products, midstream and intrastate segments, excluding SUN and USA Compression CapEx.

Now turning to our results by segment for the second quarter. And let's start with NGL and refined products. Adjusted EBITDA was $1 billion compared to $1.1 billion for the second quarter of 2024. We saw higher throughput across our Mariner East and Gulf Coast pipeline operations as well as through our fractionation facilities, which were offset by lower gains from the optimization of hedged NGL and refined product inventories, as well as lower blending margins compared to the second quarter of 2024.

For midstream, adjusted EBITDA was $768 million compared to $693 million for the second quarter of 2024. The increase was primarily due to higher legacy volumes in the Permian Basin, which were up 10% as a result of processing plant upgrades, and increased plant utilization as well as the addition of the WTG assets in July of 2024. These were partially offset by lower gathering volumes in the dry gas areas.

For our crude oil segment, adjusted EBITDA was $732 million compared to $801 million for the second quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems as well as contributions related to the recently formed Permian joint venture with SUN. These were offset by lower transportation revenues, primarily on the Bakken pipeline.

In our interstate natural gas segment, adjusted EBITDA was $470 million compared to $392 million for the second quarter of 2024. This was primarily due to higher contracted volumes on several of our interstate pipeline systems. And for our intrastate natural gas segment, adjusted EBITDA was $284 million compared to $328 million in the second quarter of last year. During the quarter, we saw increased volumes across our Texas intrastate pipeline system due to third-party volume growth. This was offset by reduced pipeline optimization as a result of shifts to more long-term third-party contracts and their price spreads compared to the second quarter of last year.

Now turning to our organic growth capital guidance. We continue to expect to spend approximately $5 billion on organic growth capital projects in 2025, even with the addition of the newly announced growth projects. We expect to achieve mid-teen returns on a majority of our growth projects, with many also providing incremental downstream benefits. We expect the majority of the upcoming earnings growth to come from our Flexport, Permian processing, NGL transportation and Hugh Brinson Pipeline expansion projects, which are expected to ramp up in 2026 and 2027. And our newly announced projects, along with our significant backlog of opportunities, are expected to provide even greater visibility into additional volumes and earnings growth through the end of the decade.

Taking a closer look at some of our recently approved and currently underway projects, we have some exciting updates on the natural gas side of our business, which are expected to support growing demand for gas-fired power plants, data centers and industrial and onshore manufacturing. First, we were very excited this morning to announce the Desert Southwest pipeline project. This strategic expansion of our Transwestern pipeline will enhance system reliability and provide new and existing natural gas demand markets in Southern New Mexico, Arizona and across the Southwest region with access to low-cost, reliable Permian Basin volumes.

This project includes construction of a new 516-mile 42-inch pipeline that will provide approximately 1.5 Bcf per day of transportation capacity from the heart of the Permian Basin to the Phoenix area in Arizona. We expect the project to cost approximately $5.3 billion, including $600 million of AFUDC, and expect the project to be in service no later than the fourth quarter of 2029.

The project is backed by significant long-term commitments with investment-grade counterparties, and we expect to launch an open season later this quarter. Also, we expect the capacity to be completely sold out upon completion of the open season. Depending on the final results of the open season, the project could be efficiently expanded to accommodate additional demand.

Phase 1 of our Hugh Brinson Pipeline is expected to provide approximately 1.5 Bcf per day of natural gas takeaway from the Permian Basin upon being placed into service, which we expect to be no later than the fourth quarter of 2026. In addition, we recently reached a positive FID on Phase 2 of the pipeline project, which will include the addition of compression. 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.

When this pipeline goes into service, we expect to have more than 2.2 Bcf per day contracted. The Hugh Brinson Pipeline will provide significant optionality by connecting shippers to our vast intrastate natural gas pipeline network and other downstream pipelines, as well as access to the majority of the gas utilities in Texas and to every major trading hub in Texas. We believe this project further establishes Energy Transfer as the premier option for customers seeking a flexible and reliable natural gas solution to support their power plant and data center growth plans.

And in July, we announced an open season on our Oasis pipeline, which offers an efficient option for shippers to sign up for future long-term natural gas transportation capacity out of the Permian Basin as it becomes available on the pipeline. This open season allows potential shippers the opportunity to ramp up their volumes over the next 4 years to better meet their projected volume growth curves. We also recently approved the construction of a new storage cavern at our Bethel natural gas storage facility. This project is expected to double our working gas storage capacity at the facility to over 12 Bcf, and we hope to place the new cavern in service by late 2028.

This expansion, which is expected to cost approximately $140 million, will increase our equity gas storage capabilities to serve growing demand in the heart of our extensive intrastate natural gas pipeline network. This will further strengthen the reliability of our systems as well as provide the opportunity to benefit from pricing volatility. We also recently approved an expansion on the SESH pipeline to serve growing power generation needs in the Southeastern region of the United States.

Looking at the Permian processing expansions. In the second quarter of 2025, Energy Transfer placed the 200 million cubic foot per day Lenorah 2 processing plant in the Midland Basin into service, and the plant is currently running at full capacity. We also recently placed the 200 million per day Badger processing plant into service, which utilized a previously idle plant that was relocated to the Delaware Basin. Volumes are ramping up nicely, and we expect to be at full capacity in the next few months.

Over the last year, we have added approximately 800 million cubic feet per day of processing capacity, including 200 million cubic feet per day of optimizations that we completed at several of our other Permian processing facilities. As a result, our process volumes in the Permian Basin recently reached a new record of nearly 5 Bcf per day, and our Y-grade transportation throughput from the Permian also recently reached a new record.

In addition, we continue to expect our Mustang Draw plant to be in service in the second quarter of 2026. At our Nederland terminal, we recently placed our Flexport NGL Export Expansion Project into ethane and propane service. And we continue to expect to provide ethylene export services in the fourth quarter of this year. The project will ramp up throughout the remainder of 2025, adding up to 250,000 barrels per day of total NGL export capacity at our Nederland terminal. This project is fully contracted beginning in January 2026, with capacity initially split 50-50 between the ethane and ethylene and propane.

We also recently approved the looping of an NGL pipeline upstream of our Lone Star Express Pipeline, which will expand our access to NGLs from the Northern Delaware Basin, where we see significant growth from our customers. Looping this pipe is expected to allow us to source an incremental 150,000 barrels per day of NGLs for transportation on our NGL pipeline system from this high-growth region. The project will cost approximately $60 million and is expected to be in [ service ] in the first half of 2027.

Now turning to Lake Charles LNG. We continue to make substantial progress towards commercialization of this project. During the second quarter, Lake Charles LNG signed an HOA with MidOcean Energy which provides a nonbinding framework for the joint development of the LNG project, with MidOcean entitled to receive 30% of the LNG production, approximately 5 million tons per annum. In addition, Lake Charles signed 20-year SPAs with Kyushu Electric Power Company and Chevron USA.

On the marketing side, we are in advanced discussions with multiple parties for our remaining capacity and are getting close to our target of 15 million metric tons per annum. Some of our potential offtake customers are also interested in equity in the project, which if concluded, would reduce our external financing requirements. As we have previously stated, we expect to sell equity in the project to reduce Energy Transfer's ownership to approximately 25%. Over the last several months, we have been working with our financial advisers to finalize marketing materials as we prepare for the launch of the equity sell-down process.

Now for a brief update around our new natural gas opportunities for new power plant and data center development. We continue to see a significant level of activity from demand pull customers to supply, store and transport natural gas for gas-fired power plants, data centers and industrial and onshore manufacturing. And we remain in advanced discussions with several facilities in close proximity to our footprint. We would expect these types of projects to generate revenue relatively quickly. Our team continues to do an excellent job of identifying the most likely opportunities, and we will continue to provide updates as we move forward.

Lastly, construction of a 10-megawatt natural gas-fired electric generation facility continues. The second facility, which is serving our Badger processing plant, was recently commissioned, and we expect 2 more facilities to be placed into service by the end of the year, with the remainder expected to be in service in 2026.

Now turning to our guidance. We now expect to be at or slightly below the lower end of our guidance range of $16.1 billion and $16.5 billion. This is a result of weakness in the Bakken, slower recovery in the dry gas areas than we expected and a lack of normal volatility in our gas optimization business from spreads and storage margins. In addition, we expected stronger growth in our Permian crude business than we have seen year-to-date.

In summary, given the substantial growth in demand for energy resources over the next several years driven by natural gas and natural gas liquids, we believe that Energy Transfer is the best positioned company in the industry to help meet this demand. We own one of the largest natural gas pipeline networks in the United States with physical assets in every major U.S. producing basin. We have more than 105,000 miles of natural gas pipelines that is coupled with significant gas storage, and we move approximately 30% of the U.S. natural gas production. We are connected to nearly 200 gas-fired power plants in the country and have the ability to leverage strong relationships to develop new projects backed by higher quality counterparties on both the supply and demand side.

We offer significant optionality, including bidirectional pipeline flow capabilities and strategically located storage assets, helping secure stable, uninterrupted supply. In addition, our operations team has extensive experience managing pipelines and a long-term proven track record of delivering reliable energy for our customers even during extreme weather events.

Building on our natural gas thing, our Hugh Brinson and Desert Southwest pipeline projects and our Bethel storage expansion project further establish our natural gas pipeline business as the leading option for customers seeking dependable natural gas supply. In addition to numerous opportunities in natural gas, we have one of the largest NGL businesses in the United States with more than 1.4 million barrels per day of NGL export capacity, and we are continuing to expand this business to meet the international demand. We also continue to evaluate projects to expand our crude oil pipeline network.

Our backlog of well contracted growth projects is expected to generate strong returns, enhance our integrated value chain and promote strong growth well into the future. We have a strong track record of organic growth, which has been enhanced by our long history of successful acquisitions. Each of these acquisitions have added strategic benefits and critical mass, providing the incremental opportunities for continued growth of our nationwide network.

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

[Operator Instructions] Our first question comes from Theresa Chen of Barclays.

Good afternoon. On the gas to power front related to data centers, following up on your comments about being in advanced discussions with demand-pull customers. Can you provide more detail on the commercialization efforts to date? What are the gating factors at this point? What is your updated view on the size and scale of the set of opportunities and when can we expect to see more discrete announcements on this front?

Theresa, this is Mackie. Let me make -- usually, I'll make a statement at the end. I will make a quick statement, and then I'll answer your question, and it kind of rolls into that answer anyway. Since Kelcy started this over 25 years ago, our partnership, we started with a 10-inch pipeline that was idle, run to about 8 counties in East Texas, and we've grown to just a massive company through acquisitions and also through enormous organic projects throughout the U.S.

And as I sit here today, we look at the folks that are running our business, both in office and especially out in the field and we look at the adversity that we have unparalleled to any of our competitors by far, even with this challenged quarter that we had that we're certainly going to talk about, I've never been -- I'm sure [ body in here ] joins me is excited about where we sit and where the future is for our industry, but even more importantly, for this call for our partnerships. So we're very excited about that, and a lot of that drive comes to your question.

I've kind of been taking a ribbon for the last 3 months from these -- our guys saying don't say 4 to 6 weeks on something. So I'm going to be a little careful there. But I will say this. These data centers have come out of nowhere. It's a huge and enormously upside for companies like us that have big inch pipes all over the U.S. in very well-located areas for these types of projects, but they're different. And they're different in a couple of ways. One, these aren't a plant that cost $1 billion or $0.5 billion. These are $50 billion, $60 billion, $100 billion-type facilities that we're building to. So these things don't just happen overnight. It takes time. And even the announcement on the Desert Southwest, it took 3.5 years to develop that. So it has taken time. I, we are going to be more careful about what we say, but let's say this. I can't say this.

Several months ago, we did sign our first kind of significant deal with a hyperscaler, a behind-the-meter hyperscaler here in Texas. It was 80,000 a day. We have recently, as of now, today increased that to 380,000 a day with the [ flex right ] to go to 475, maybe more upside from that from this one area in Texas. But it's just one of -- we've signed 3 deals now in Texas. We're very close to 2 more. We've signed very close to signing one pretty significant one outside. But I'm not saying that's 2, 3, 4, 5, 6 weeks, however long it takes. Every data center has different needs, different requirements, different supply sources, et cetera, et cetera. So it does take a while to put these together. This one came together fairly quickly in light of how excited we are about it. We're also excited about a lot of these others we're chasing.

So without making promises on new data center and/or a new power plant supporting data centers, any kind of predictions on weeks, just stay tuned. We're pretty excited about what we anticipate announcing over these coming quarters.

And turning to the transmission side of things. Congratulations on the FID of Desert Southwest. Can you provide color on the expected build multiple for this project? And at this point, how much of the 1.5 Bcf per day is committed? And pending the results of the open season, to what extent can it be expanded?

So gosh, we haven't announced something in a while that is exciting as this. Beth Hickey and her team did an incredible job. This is just keeping your head to the grindstone for the last 2.5-plus years, very excited. We kept hearing about other projects, kind of ignored that, paid attention to what we do, and we're very excited.

Yes, we haven't fully sold that out. We have 0 concerns about selling out. In fact, to expand on a little bit, because of the incoming calls that we've had today, because of other conversations we've had over the last 3 or 4 weeks of folks that aren't in heavy negotiation with us yet, not only do we have 0 worries about fully selling out the 1.5, we also kicked off an evaluation today to increase that to a 48-inch, which would more than double the 1.5 Bcf. Certainly not indicating that all on this call, but that's what we're going to do. But because of the enormous demand growth along this pipeline and in the Phoenix area, there's just some upside that's probably going to make sense, seriously looking at that. And if we do and get that going, we are confident that we'll sell that out. So yes, from the standpoint of returns, there's some upside that I kind of want to talk to about on this call, but like everything else this size, we're going to be in that mid-teens kind of worst case on the returns on this project.

Our next question comes from Jeremy Tonet of JPMorgan.

Good afternoon. I just wanted to pivot to Lake Charles, if I could. And maybe I missed it, but just wanted to see where we were with the EPC quote process and firming that up and I guess, marrying that against the SPAs and commercial agreements that you've established so far?

Yes, this is Mackie again. And Tom is here for any follow-up adders he wants to add. And then [ Raj ] is here too, who is working closely, has been with EPC contracts for a while. We've had our own expectations as we're waiting kind of for the numbers that have come in, and they're dead on to what we expected. We certainly are including tariff which seemed to change daily, but any kind of tariff impact on that. So we're very pleased of where the EPC contract looks like it's going to come out. It's right where we expect it to be, fits very well with what we've contracted and what we remain the contract. So we're -- as Tom said in the opening statements, we've been saying this for I don't know how many years.

We're very excited about this. We are pushing hard to get to the finish line, and we're going to do everything we can to make that happen, but we still got some work to do, but there's a lot of interest on this project, and we believe we'll get there over the next couple of months. And then as we said, kick off the financing and get it to FID as soon as we can.

Got it. And then pivoting back to Desert Southwest, congratulations there. I was just wondering if you could share your thoughts, how ET views construction cost risk sharing as well as dealing with tribal land?

Okay. This is Mackie again. As you can imagine, we've looked at that very closely over the last year, 1.5 years. If we have -- we expect to have 0 right of way across travel lands. And we don't foresee of what we've seen so far, any issues right of way. We're certainly going to be out in front of this, communicating, of course, with FERC, with the Department of Energy, Department of Interior, as well as we'll be heavily involved in discussions with the governors of both New Mexico and Arizona as well as Texas. And we'll be boots on the ground with our government relations team and those counties that we'll be going through in all these 3 states.

And so we're -- we've paid a lot of attention to that. We have put some contingency with some unknowns that we certainly don't know about today. But we -- I feel very good about where the costs are and very confident that we will meet or come in under the cost that we are estimating at this time.

Our next question comes from Keith Stanley of Wolfe Research.

And sorry to beat the dead horse on Desert Southwest. But I guess starting big picture, what do you see as what your competitive advantage was in winning this project over your peer, especially since it kind of goes along the route of their existing pipeline? Just how did you win this out and basically get all the utilities to support your project?

Yes. Great question. I guess I go back to my opening statement. We just got some good people and we've got some good assets. And we did a great job of being patient, as I mentioned, and kind of rebuild a little bit. We've heard off and on that several other projects were about to go and all that stuff. And we just ignored that. We don't worry about what other companies are doing. We worry about what we're trying to get to the finish line.

So with our team, their ability to negotiate and what we offer as far as supply sources. I mean, we're tying to some big intrastate pipelines as sources, we're tying to a lot of our large cryogenic facilities. So kind of tying all that together. We -- as we've done over the years, we're pretty good at using synergistic upside to projects that we get to the finish line on. So a combination of all of that and just paying attention to the customers and responding to their needs and tough negotiations on all sides. We got a fair deal across the board, I think. I think our customer, very pleased with where we're at and just kudos to Beth and her team and all the work on our engineering behind all that and all the other support from a lot of the folks are in this office.

Great. And then I wanted to clarify the two earlier questions. So first, if you're saying mid-teens returns on Desert Southwest, I mean, given it's a 4.5 year kind of permitting and build period. Is it fair to assume that's, call it, a 6x EBITDA multiple or better? And then I wanted to follow up on Jeremy's question. Is there any cost sharing mechanism if you do run into hiccups on this project? Or is it a traditional structure where the midstream company is the one that's in control of the costs and takes that risk?

It's a traditional deal. That's just what we do. We know some of our competitors go out and do projects and low ball the rates, but say if the rates come on -- cost coming higher, it will go up. So no, this is how we built this partnership. We do a lot of work, a lot of studying, and we've got a lot of good folks doing our right-of-way estimations and our pipeline and compression costs. And we feel -- like I said earlier, we feel real good. We've got tariff cost in these. We've got contingency costs in these, we feel real good about it. And to your first half of your question, yes, 6x is a pretty good number to look at to consider.

Our next question comes from Jean Ann Salisbury of Bank of America.

I wanted to go back to the comment about 2025 fundamentals being a little bit weaker than you guys had forecast in the Bakken, Permian crude and gas growth. Is that kind of year-to-date comments or more just what you're seeing in the back half?

Jean, this is Dylan. Good question. It's a little bit of both. I think that we -- through the beginning of the year, we're just seeing a little bit lower volume. Some of that was coming out of the fourth quarter. Our plan had some growth in those we just haven't seen materialize. To the extent that we plan, we are still think strong volumes in the majority of our areas, just not quite at the growth rate that we expected.

And so looking at the back half of the year, kind of a continuance. We see some growth coming, but we got a little bit of catch-up to get up to where we expected to be at this time of year. And so it's like I said, you got a little bit on both parts of the year.

Yes. And if you don't mind, let me add to this. We couldn't be more bullish about Bakken. No, that sounds odd because it certainly was kind of a black eye, it looks like for us in the second quarter, but there's a lot of things happening on the scene. I'll just touch on a few of them real quick. We had the TMX expansion project came on about a year ago. What that's done is we've taken crude oil to refineries and more importantly now to export to Asia. It pulled a lot of the Canadian barrels out. That opened up some capacity on some pipelines out of Canada that now could be filled into a certain degree. With 1 of our competitors taking Bakken out, that's going to go away in the next 1.5 years to 2 years. That window is going to close and the volume growth in Canada is going to fill that up, and so those volumes are coming back.

Secondly, what happened quarter-to-quarter was we saw volumes come off. We had some cold weather up there in April and May that slowed down completions. There were some deferments of completions. There were even some curtailments, and we saw about 50,000 barrels a day less volume for the second quarter. In addition to that, there are also fires that had impact on barrels moving through both TMX projects, the original and the expansion. And so what that caused was a lot of refineries both in Canada and in the Northwestern U.S. really paid up to get oil to their refineries because they were short out of Canada. And so increased our business through our rail terminals but took some volumes off of our pipeline that's coming back.

So you kind of add all that up, there's 80,000, 90,000 100,000, 120,000 barrels that have been kind of going in different directions or weren't being produced that are going to come back in the system. And in addition to that -- and there's no questions about this yet, but I'm going to ahead and talk about it because I'm excited -- we're excited about it. Adam and his whole team is that we've got this open season going with [ Enbridge ]. And what Energy Transfer has done a good job on all these years is we look at our assets, we look at they're being utilized. As everybody knows, we converted a natural gas pipeline interstate into a crude line that now helps move Bakken to the Gulf Coast. We converted an interstate pipeline out in West Texas and Mexico to an NGL, we converted another pipeline to diesel, and that's kind of what we do.

But we also look at how do we keep our pipelines full today and more importantly, for the next 10 or 15 years? And what's going on in Canada is exciting to us. There's a lot more egress needs to get out. And what better way than to help Canadian producers get production out to a pipeline that already exists. No risk on building, not just on any kind of other issues. And so we're excited about that. We think it's a great opportunity to help Canadian producers. But more importantly, we're going to do everything we can to make sure the producers in North Dakota have an outlet on our pipeline. But in addition to that, we have the ability to increase by adding pumps, capacity or pipeline. And so it fits very well in working with [ Enbridge ] to help get more production out of the Canadian. So once again, I'll start -- I'll end where I started. We're very excited about the future of the Dakota Access.

That's great. As a follow-up, as you know, there's a lot of NGL pipeline capacity coming on in the Permian this year and next. Can you kind of dimension, I guess, how much volume loss you think you could see on Lone Star and whether the North Delaware looping project you announced today would offset most of that, maybe all?

Yes. Our [ night ] fracs coming on the end of next year. So that kind of plays a role in all of this. We've got to have a home for it. But yes, we're right on target. As Tom mentioned in the opening statements, we're bringing these [ crypto up ], Lenorah 2. We've got Badger up and ramping up quickly. We'll have Mustang Draw up first quarter, I think, of next year. We're doing everything we can to get the barrels out of Delaware. That's the $60 million expansion to get more down further stream. We've got more capacity on our existing Lone Star, as you just mentioned. And we feel real good about new contracts that we're signing, of course, the ones that relate to [ on Crows ], new contracts with other third-party processing plants and then deals that were -- that are coming up for termination. We're being very aggressive of growing those other -- over.

So we're focused, we've got a whole team working on this. Like I said, on Dakota Access to keep these pipelines full, to build them to the capacity we need them and then through time to fill them up and then as time goes on, make decisions on further expansions. But we feel real good about where we're at and kind of the timing when barrels start showing up with the completion of some of these projects that we have going on, including the Delaware expansion.

Our next question comes from Gabe Moreen of Mizuho.

I just wanted to ask on -- it seems like a long time ago at this point, the whole [ Epstein ] export saga. But a, whether that had any impact at all on your quarterly results, but b, bigger picture, as you're thinking about some of your expansions and other types of projects, whether it changes your plans in terms of markets you may be targeting either for ethane or ethylene exports and just how things would go in the future commercially for that?

Yes. The first half of your question, no impact. Fortunately, it didn't last long enough to have an impact. We weren't concerned about it. The only impact, I'd say, I would say that it had was when you have deals with companies, international companies, all these years, they've relied on you do business with the U.S. honors. So that put a little bit of a black eye on us on our industry, on our country when we've got contracts and billions of dollars that were spent on crackers in this case in China with -- in our case, with a very good partner with satellite. It was -- it wasn't fun, but we worked our way through it. Fortunately, that has gone away.

We think it's going to be probably a little bit more difficult to contract with Chinese crackers, good or bad. We think that they're probably going to be a little bit more hesitant. So to your question, yes, as we've always done, we're looking at other countries, other companies in other countries, and we're beating the bushes and there's a lot of opportunities there, and we're certainly very optimistic and believe that we will have further expansions. We'll need further expansions both at Marcus Hook and at Nederland, and those will come, but this whole ethane issue that popped up here over the last several months certainly slowed things down with China.

And maybe if I can ask just hydraulically in terms of what's going on with the Hugh Brinson Pipeline in terms of the ability, I think, to make it bidirectional at this point. Are your customers just looking to wheel gas in terms of different points around? Or can you just maybe give us some more color in terms of what those hydraulics kind of do for the project and what sort of demand you're looking to meet there with that?

We've talked -- we've been pretty excited about Desert Southwest, but it's hard not to be as, if not more excited about Hugh Brinson. Couldn't have been better timing. We missed a lot of projects through the years, but we hit the rate of returns that we needed finally on this project when we got it to the end zone. It's got tremendous interest. We have 0 interest about selling it out, and we're looking at maybe the next stage.

But we also -- by adding the bidirectional capability, we are able to offer other supply sources for our Texas markets. And so it's really added a boost, especially revenue boost potential for that project to make it a lot better rate of return than what we initially expected.

So as I mentioned earlier, we just -- if you look at all our assets out of the country, it's exciting, but gosh, especially in Texas. If you want to build a data center in Texas, who in the world would you want to do it better than Energy Transfer? When you look at all the 42-inch, 36-inch we have, all the storage support we have behind that and our ability and kind of path to being able to deliver at critical times. So we feel real good about that, and Hugh Brinson is going to be a great project for us for many years to come. And we're very fortunate it kicked off when we did.

Our next question comes from Manav Gupta of UBS.

Congrats on all the projects. I just wanted to quickly focus on Slide 8. It says 50% of your growth capital will be on nat gas focused projects for 2025. I'm trying to figure out, given all these new projects which are being announced, what would that number be for '27-'28? I'm not looking for an exact number, but should we assume that number trends upwards from here?

Yes. I think that's safe to assume that number turns up. Obviously, we got a lot of time between now and then and a lot of projects that the team is working on a lot of great projects. Then we will look forward to bringing rate announcement here over the next couple of years. But right now, as we look at -- yes, I think that number would trend higher once the books right now, particularly like that -- with the Desert Southwest project.

Perfect. My quick follow-up here is a number of people are trying to develop this LNG. But you are somewhat unique because you have all these pipelines to feed your own LNG. So can you talk about the benefits of vertical integration of moving ahead with Lake Charles, given all the infrastructure that you have in place to feed your LNG facility?

Yes, this is Mackie again. Yes, as we've mentioned over the years, we're very excited about LNG. But what really drives us on LNG is pipeline transportation business that we're so good at and that what's kind of built our company. So as you mentioned, we've got multiple pipeline route into that area and into Lake Charles. We certainly will look at an expansion of a pipeline system to bring in more volumes once we get to FID. And we're very excited about that aspect of the project. I mean LNG is going to be a great project. It's going to be a good rate of return for us, but the real upside is our pipeline transportation business upstream of Lake Charles.

Our next question comes from Michael Blum of Wells Fargo.

Wanted to go back to Lake Charles and really just clarify your goal to get to 15 million metric tons to get to FID. Does that need to be all firm contracts? Or will you proceed with the combination of HOAs and SPAs?

And Tom may correct this or modify it, but what we plan on doing is once we have FDA and/or HOAs initially -- I'm sorry, HOA or SPAs, we will move forward on finance, kicking off financing once we have our target level of either one, a combination of both. So the HOAs are, for all practical purposes, end up being binding, even though they're not. But we -- with all the parties we're dealing with, once we sign the SPA, we're 99% positive. We'll get to an HOA -- once we sign an HOA -- but once we sign an HOA, we're very confident that we'll get to SPA in a fairly relatively short period of time.

Okay. Great. That helps. And then I just wanted to ask about how we should think now about the cadence of growth CapEx beyond this year now that you've got Desert Southwest, Lake Charles is moving towards FID, it seems? And you've also announced here, another steady rate of additional projects. So -- and it seems like there's a lot more behind this. So just wanted to get a sense for the cadence beyond this year.

Michael, listen, this is Tom, and I know that Dylan was walking through that a little bit, one of the previous questions. But that is fair. With all these good projects we're having right now, we are seeing that grow. We'll probably be ready later this year to be able to give a little more guidance around that. We normally wait until the year-end earnings call to provide the guidance for 2026. But with all the moving pieces here right now, on a lot of very, very good projects that we're excited about.

Just give us a little bit later, but you can appreciate though, those are going to be coming up. And that's not just the Desert Southwest, the Hugh Brinson, the storage all the projects we're talking about right now. And in Lake Charles, when Lake Charles gets going, that one, likewise, we'll be rolling that one in. So just give us a little more time with all the moving pieces. But you can see that definitely going up.

Our next question comes from Zach Van Everen of TPH.

Maybe going back to the AI power projects. Great to hear the hyperscaler contract that you spoke to. It seems like a lot of these projects are on or around existing assets. And I know you probably can't give an exact number, but is there a range of EBITDA contribution from these projects you could point to? If it's within a mile of the facility, is it a lower contribution? Just trying to get an idea of what these projects might look like.

Yes, this is Mackie. It's probably a little early on to get to that kind of detail. And the reason being is, some of these we may have a mile or two away, some of them, we may have 25 miles away. For the most part, they're much closer to our systems, but we will have an added fee for that. But I guess I would state that as we get more and more of these done, it will be a very impactful number from an EBITDA perspective and every single project will have -- some will have much higher EBITDA impact than others. But I don't think on this call, I can really quantify exactly what that is, but we are very bullish on where all the -- where that business is going to take us.

Sounds good. And maybe shifting back to the NGL looping project. Just curious if the 150 barrels is shifting off of another system? Or is this expected to be kind of incremental growth from producers in that area?

It will be incremental growth. As Badger ramps up, we're running out of capacity where we've got more growth up in the Southern Delaware and New Mexico. So it's -- we expect growth, rolling over contracts that exist, new growth on our power [ process ] plants that are coming online as well as third-party processing plants that our NGL team is actively negotiating it.

Our final question comes from John Mackay of Goldman Sachs.

I think Manav asked this 1 way, but I might ask another. Just looking more broadly, now to a ton of gas projects now, do you have a sense of what percentage of the overall business gas could look like as we look forward a couple of years?

Yes, John, this is Mackie. When you say overall, you mean kind of like a Bcf?

Sorry, I guess, percentage of total ET EBITDA.

I don't think at this point, we'd give an exact number on that. Like you said, there's a lot of projects in the works and a lot of good growth opportunities in all of our segments here. I'd say -- as you look right now and you look at the main segments there with the expansion of -- the 2 biggest expansion projects with the Hugh Brinson in intrastate and Desert Southwest in the interstate, obviously, the expectation is for those segments to grow as a percentage of the whole, probably the quickest of any of our segments as we look out.

And maybe taking that just a little further. I mean, with a lot of these -- a couple of these projects being a little later dated, are you guys getting into a position where you might be able to talk about kind of a go-forward kind of EBITDA growth rate target from here or anything like that, maybe not necessarily guidance, but at least a framework or a general target?

Yes, listen, this is Tom again. That's not been something that we probably bounced around here a lot as far as the discussion. Clearly, with all this happening, we always have a very, very robust forecasting process around here. So we're always in front of rating agencies with those, et cetera. We could consider that. But I think as we sit here right now, we've not necessarily discussed giving some type of a growth trajectory. Our [ skit's ] a little bit lumpy, especially when you blend it in with the M&A. So an acquisition comes along, you can probably appreciate the fact that sometimes that will all of a sudden make a jump. And then other times, we're talking about the projects we are right now, which all have varying years of build that come with them.

So anyway, Dylan, I don't know if you want to add a little bit more to that?

I'll just point back to one thing that we've said publicly before, which is we have our stated growth target for distributions of 3% to 5%. And the additional color we've given around that is that that 3% to 5% for us has to provide a baseline for where we believe is a floor to the long-term growth in distributable cash flow per unit. We're not manufacturing our plan is not to manufacture distribution growth by getting into coverage. So that number is meant to provide a floor for the long-term growth rate there at a bare minimum.

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

All right. Well, listen, we thank all of you for joining us, as always, and we look forward to the follow-up calls. I hope everyone has a good rest of your day.

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.