Energy Transfer LP

and welcome to the Energy Transfer Second Quarter 2025 Earnings Conference Call. At this time, all participants are in listen-only mode. Should you need assistance during the conference call, you may signal an operator by pressing the star key followed by zero. After today's presentation, there'll be an opportunity to ask questions. To ask a question, you may press star, then one on your telephone keypad. To withdraw your question, please press star, then two. 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 McCree 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 that 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 Security 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 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 six months of 2025, we spent approximately $2 billion in organic growth capital, primarily in the NGO 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 all set 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 error 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 the 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 Branson 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 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 one 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. We recently reached a positive FID on phase two 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 four 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 Lenora II 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 idled 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 five 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 Needland terminal, we recently placed our Plexport 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 needle and 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 Mid-Ocean Energy, which provides a non-binding framework for the joint development of the LNG project with Mid-Ocean entitled to receive 30% of the LNG production, approximately 5 million tons per annum. In addition, Lake Charles signed 20-year SBAs with Kyushu Electric Power Company and Chevron USA. On the marketing side, we're 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 uptake 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 transfers ownership to approximately 25%. Over the last several months, we have been working with our financial advisors 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 pool 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 eight 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 two 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 theme, our Hugh Branson 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 lineup for our first question.

Thank you. We will now begin the question and answer session. To ask a question, you may press star, then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing any keys. We ask that you please stick to one question and one follow-up. If at any time your question has been addressed and you would like to withdraw from the queue, please press star, then two. At this time, we will pause momentarily to assemble our roster. Our first question, comes from Teresa Chen of Barclays. Please go ahead.

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?

Hey, Teresa, 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 Kelsey started this over 25 years ago, our partnership, we started with a 10-inch pipeline that was idle, run through about eight 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 diversity that we have unparalleled to any of our competitors by far. Even with this challenge quarter that we have that we're certainly going to talk about, I've never been, I'm sure everybody in here who 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 partnership. 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 three months from our guys saying that Don't say four to six 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, you know, a plant that costs a billion dollars or half a billion. These are $50, $60, $100 billion-dollar type projects. facilities that we're building to. So these things don't just happen overnight. It takes time. Even the announcement on the desert southwest, it took three and a half years to develop that. So it has taken time. We are going to be more careful about what we say, but let's say this. I can 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 that 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 $475,000, maybe more upside from that, from this one area in Texas. But it's just one of, we've signed three deals now in Texas. We're very close to two more. We've signed, very close to signing one pretty significant one outside. But I'm not saying that's two, three, four, five, six 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 new power plants 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.

Thank you. 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 as exciting as this. Beth Hickey and her team did an incredible job. This is just keeping your head to the grindstone for the last two and a half 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 zero 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 three or four weeks of folks that aren't in heavy negotiations with us yet. Not only do we have zero 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 at all on this call that 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 will sell that out. So yes, from the standpoint of returns, there's Some upside that I kind of won't talk to about on this call, but it's 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 Tonette of JP Morgan. Please go ahead.

Hi, good afternoon.

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.

Yeah, this is Mackie again. And Tom's here for any follow-up matters he wants to add. And then Raj here, too, who's working closely with the EPC contract for a while. You know, 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 tariffs, which seem 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. It fits very well with what we've contracted and what we remain in the contract. So as Tom said in 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. Thanks for that. 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 lands?

Okay, this is Mack again. As you can imagine, we've looked at that very closely over the last year, year and a half. We expect to have zero right-of-way across tribal lands, and we don't foresee of what we've seen so far, any issues right away. 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 and all these three states. 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 I feel very good about where the costs are and very confident that we will meet or come under the cost that we're estimating at this time.

Got it. That's helpful. Thank you.

Our next question comes from Keith Stanley of Wolf Research. Please go ahead.

Hi, good afternoon, 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. You know, 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 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, 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. Combination of all that and just paying attention to customers and responding to their needs and, you know, tough negotiations on all sides. We got a fair deal across the board, I think. I think our customers are very pleased at 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 who are in this office.

Great. Thanks for that. 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 four and a half year kind of permitting and build period, is it fair to assume that's, you know, call it a six times EBITDA multiple or better? And then I wanted to follow up on Jeremy's question. Is there 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 lowball the rates, but say if the rates come in higher, I mean, costs come in higher, it will go up. So, no, this is how we built this partnership. We do a lot of work, a lot of studying. 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 costs in these. We've got contingency costs in these. We feel real good about it. And to your first half of your question, yeah, six times is a pretty good number to look at, to consider.

Thank you.

Our next question comes from Jean M. Salisbury. of Bank of America. Please go ahead.

Hi. 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 a year-to-date comment or more just what you're seeing in the back half?

Good question. It's a little bit of both. I think that we, you know, Through the beginning of the year, we're just seeing a little bit lower volumes. Some of that was coming out of the fourth quarter. Our plan had some growth in there that we just haven't seen materialize to the extent that we planned. We are still seeing 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've got a little bit of catch-up to get up to where we expect it to be. at this time of year. And so, like I said, you got a little bit on both parts of the year.

Yeah. And if you don't mind, let me add to this. We couldn't be more bullish about Bakken. Now, 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 behind the scene. I'll just touch on a few of them real quick. You know, we had the TMX expansion project came on about a year ago. What that's done is taken crude oil to refineries and, more importantly now, to exports 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 in to a certain degree with one of our competitors taking Bakken out. That's going to go away in the next year and a half to two years. That window's 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 were 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 the refineries both in Canada and in the northwestern U.S. really paid up to get oil to the refineries because they were short out of Canada. And so it increased our business through our rail terminals but took some volumes off of our pipelines that's coming back. So you kind of add all that up. There's 80, 90, 100, 120,000 barrels that have been kind of going 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 question about this yet, but I'm going to go ahead and talk about it because we're excited about it, Adam and his whole team, is that we've got this open season going with Enbridge. And what InterTransfer has done a good job on all these years is we look at our assets, we look at their being utilized. As everybody knows, we converted a natural gas pipeline interstate into a crude line that now helps move Boston to the Gulf Coast. We converted an interstate pipeline pipeline out in West Texas and New Mexico to an NGL and convert 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, no risk 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 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 to our pipeline. And so it fits very well in working with Enbridge to help get more production out to Canadians. So once again, I'll start with Laura. I'll end where I started. We're very excited about the future of Dakota Access.

That's great. Thank you for all of that detail. 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?

Yeah, our ninth track's coming on the end of next year, so that kind of plays a role in all this. We've got to have a home for it. But, yeah, we're right on target. As Tom mentioned in the opening statements, we're bringing these cryo up. We're going over two. 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 are related to our own crowds, new contracts with other third-party processing plants, and then deals that are coming up for termination. We're being very aggressive of rolling those over. So, you know, we're focused, and we've got a whole team working on this. Just 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 of where we're at and kind of timing when the barrels start showing up with the completion of some of these projects that we have going on, including the Delaware expansions.

Great, I'll leave it there.

Thanks for all the detail. Our next question comes from Gabe Maureen of MISU. Please go ahead.

Good afternoon, everyone. I just wanted to ask on, it seems like a long time ago at this point, the whole FSA and 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?

Yeah, the first half of your question, no impact. Fortunately, it didn't last long enough to have an impact. We were concerned about it. The only impact I'd say we'd say that it had was when you have deals with companies, international companies, you know, all these years they've relied on you do business with the U.S., the U.S. honors it. 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, in our case with a very good partner with satellite. 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.

Thanks, Mackie. 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 just to maybe give us 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?

You know, we've talked and 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 zero 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. It's really added a boost, especially a revenue boost potential for that project to make it a lot better rate of return than what we initially expected. As I mentioned earlier, you look at all our assets throughout 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 deal with better than any 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, you know, 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.

Thanks, Mackie.

Thank you.

Our next question comes from Manav Gupta of UBS. Please go ahead.

Good afternoon. Congrats on all the good projects. I just wanted to quickly focus on slide eight. It says, you know, 50% of your growth capital will be on net 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?

Yeah, I think that's safe to assume that number shows up. Obviously, we have a lot of time between now and then, and a lot of projects that the team's working on, a lot of great projects that we will look forward to bringing to announcement here over the next couple of years. But right now, as we look out, I think that number would trend quite a bit higher, what's on the books right now, particularly 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?

Yeah, this is Mackie again. As we've mentioned over the years, we're very excited about LNG, but what really drives us on LNG is the pipeline transportation business that we're so good at and that's kind of built our company. So as you mentioned, we've got multiple pipeline routes 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.

Thank you so much. Our next question comes from Michael Bloom of Wells Fargo. Please go ahead.

Thanks. Good afternoon, everybody. I 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 a combination of HOAs and SBAs?

Tom may correct this or modify it, but what we plan on doing is once we have SPAs and or HOAs initially, I'm sorry, HOAs or SPAs, we will move forward on financing, 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 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 the HOA, this is more Tom's area, but once we sign the HOA, we're 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. And it seems like there's a lot more behind this. So I just wanted to get a sense for the cadence beyond this year. Thanks.

Yeah, 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 those are going to be coming up. And that's not just the Desert Southwest, the Hugh Brinson, the storage. you know, all the projects we're talking about right now. And if Lake Charles, when Lake Charles gets going, that one likewise, you know, 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.

Thanks, Tom.

Our next question comes from Zach Ben-Everin of TPH. Please go ahead.

Hi, all. Thanks for taking my question. Maybe going back to the AI power projects, great to hear the hyperscale 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 you know, a lower contribution, just trying to get an idea of what these projects might look like.

Yeah, just back again. It's probably a little early on to get to that kind of detail. And the reason being is, you know, some of these we may have a mile or two delay. Some of them we may have 25 miles delay. 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, you know, some will have much higher EBITDA impacts than others. But I don't think on this call we can really quantify exactly what that is, but we are very bullish of where that business is going to take us.

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

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

Perfect. Appreciate the time. Thanks, everyone.

Thank you.

Our final question comes from John McKee of Goldman Sachs. Please go ahead.

Hey, everyone. Thank you for the time. I think Manav asked this one way, but I might ask him another. Just looking more broadly, you've announced 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?

Yeah, 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. As you look right now and you look at the main segments there with the two biggest expansion projects with the Hubertson Intrastate, the Desert Southwest, and 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 farther, 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?

Yeah, listen, this is Tom again. That's not been something that we've probably bounced around here a lot as far as 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, etc. 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. Ours gets a little bit lumpy, especially when you blend it in with the M&A. So when acquisition comes along, you can probably appreciate the fact that sometimes that'll 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. Anyway, Dylan, I don't know if you want to add a little bit more to that.

I just point back to one thing that we've said probably 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 3% to 5% for us has to provide a baseline for where we believe is a 4% to the long-term growth in terminal cash flow per unit. We're not manufacturing. Our plan is not to manufacture distribution growth. by eating into coverage. So, you know, that number is meant to provide a floor for the long-term growth rate there at a bare minimum.

That makes sense. Appreciate the time. Thank you.

Thank you.

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. Hope everyone has a 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.