ET - NYSE

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 eight 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 Transfer's 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 worked 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 one 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, [ Hex ] 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 one 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 diameter 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? It 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 loop and pipe. We're going to have to be required to loop Hugh Brinson, make it a bigger project. We could forego 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 -- 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. Tom, I appreciate taking a swing at 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'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're -- 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 Bcf, but we'll see how the next six 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 [ end of the ] 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 [ 2030 ], 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 go anywhere 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 -- as 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 [ Uri ] 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, Fermi and 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 [ low and behold ], we go through right by Abilene with 1 of the largest -- potentially largest data centers in Texas. 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 [indiscernible]. But we look at [ the land too ]. 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-projects 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 pull gas from our system in the event they've got interruptions from there. 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 -- 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

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 four pipelines announced. Depending on rumors, about one of those going to a 48-inch, possibly one 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 in 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'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 [ draft ] 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 be the 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. What 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.