Good afternoon, everyone, and welcome to the Energy Transfer Second Quarter 2025 Earnings Call. I'm also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon. As a reminder, our earnings release contains a thorough MD&A that goes through the segment results in detail, and we encourage everyone to take a look at the release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended June 30, 2025, which we expect to file tomorrow, Thursday, August 7. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. So let's start today by going over our financial results. For the second quarter of 2025, we generated adjusted EBITDA of $3.9 billion compared to $3.8 billion for the second quarter of 2024. We saw several volume records during the quarter, including the midstream gathering, crude transportation, NGL transportation, NGL and refined products terminal and NGL export volumes. We also saw strong volumes through our NGL fractionators, natural gas inter- and intrastate pipelines. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2 billion. And for the first 6 months of 2025, we spent approximately $2 billion in organic growth capital, primarily in the NGL and refined products, midstream and intrastate segments, excluding SUN and USA Compression CapEx. Now turning to our results by segment for the second quarter. And let's start with NGL and refined products. Adjusted EBITDA was $1 billion compared to $1.1 billion for the second quarter of 2024. We saw higher throughput across our Mariner East and Gulf Coast pipeline operations as well as through our fractionation facilities, which were offset by lower gains from the optimization of hedged NGL and refined product inventories as well as lower blending margins compared to the second quarter of 2024. For midstream, adjusted EBITDA was $768 million compared to $693 million for the second quarter of 2024. The increase was primarily due to higher legacy volumes in the Permian Basin, which were up 10% as a result of processing plant upgrades and increased plant utilization, as well as the addition of the WTG assets in July of 2024. These were partially offset by lower gathering volumes in the dry gas areas. For our crude oil segment, adjusted EBITDA was $732 million compared to $801 million for the second quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems as well as contributions related to the recently formed Permian joint venture with SUN. These were offset by lower transportation revenues, primarily on the Bakken pipeline. In our interstate natural gas segment, adjusted EBITDA was $470 million compared to $392 million for the second quarter of 2024. This was primarily due to higher contracted volumes on several of our interstate pipeline systems. And for our intrastate natural gas segment, adjusted EBITDA was $284 million compared to $328 million in the second quarter of last year. During the quarter, we saw increased volumes across our Texas intrastate pipeline system due to third-party volume growth. This was offset by reduced pipeline optimization as a result of shifts to more long-term third-party contracts and their price spreads compared to the second quarter of last year. Now turning to our organic growth capital guidance. We continue to expect to spend approximately $5 billion on organic growth capital projects in 2025, even with the addition of the newly announced growth projects. We expect to achieve mid-teen returns on a majority of our growth projects, with many also providing incremental downstream benefits. We expect the majority of the upcoming earnings growth to come from our Flexport, Permian processing, NGL transportation and Hugh Brinson Pipeline expansion projects, which are expected to ramp up in 2026 and 2027. And our newly announced projects, along with our significant backlog of opportunities, are expected to provide even greater visibility into additional volumes and earnings growth through the end of the decade. Taking a closer look at some of our recently approved and currently underway projects, we have some exciting updates on the natural gas side of our business, which are expected to support growing demand for gas-fired power plants, data centers and industrial and onshore manufacturing. First, we were very excited this morning to announce the Desert Southwest pipeline project. This strategic expansion of our Transwestern pipeline will enhance system reliability and provide new and existing natural gas demand markets in Southern New Mexico, Arizona and across the Southwest region with access to low-cost, reliable Permian Basin volumes. This project includes construction of a new 516-mile 42-inch pipeline that will provide approximately 1.5 Bcf per day of transportation capacity from the heart of the Permian Basin to the Phoenix area in Arizona. We expect the project to cost approximately $5.3 billion, including $600 million of AFUDC, and expect the project to be in service no later than the fourth quarter of 2029. The project is backed by significant long-term commitments with investment-grade counterparties, and we expect to launch an open season later this quarter. Also, we expect the capacity to be completely sold out upon completion of the open season. Depending on the final results of the open season, the project could be efficiently expanded to accommodate additional demand. Phase 1 of our Hugh Brinson Pipeline is expected to provide approximately 1.5 Bcf per day of natural gas takeaway from the Permian Basin upon being placed into service, which we expect to be no later than the fourth quarter of 2026. In addition, we recently reached a positive FID on Phase 2 of the pipeline project, which will include the addition of compression. This system will be bidirectional, with the ability to transport approximately 2.2 Bcf per day from west to east and approximately 1 Bcf per day from east to west. When this pipeline goes into service, we expect to have more than 2.2 Bcf per day contracted. The Hugh Brinson Pipeline will provide significant optionality by connecting shippers to our vast intrastate natural gas pipeline network and other downstream pipelines, as well as access to the majority of the gas utilities in Texas and to every major trading hub in Texas. We believe this project further establishes Energy Transfer as the premier option for customers seeking a flexible and reliable natural gas solution to support their power plant and data center growth plans. 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 Lenorah 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 idle plant that was relocated to the Delaware Basin. Volumes are ramping up nicely, and we expect to be at full capacity in the next few months. Over the last year, we have added approximately 800 million cubic feet per day of processing capacity, including 200 million cubic feet per day of optimizations that we completed at several of our other Permian processing facilities. As a result, our process volumes in the Permian Basin recently reached a new record of nearly 5 Bcf per day, and our Y-grade transportation throughput from the Permian also recently reached a new record. In addition, we continue to expect our Mustang Draw plant to be in service in the second quarter of 2026. At our Nederland terminal, we recently placed our Flexport NGL Export Expansion Project into ethane and propane service. We continue to expect to provide ethylene export services in the fourth quarter of this year. The project will ramp up throughout the remainder of 2025, adding up to 250,000 barrels per day of total NGL export capacity at our Nederland terminal. This project is fully contracted beginning in January 2026 with capacity initially split 50-50 between the ethane and ethylene and propane. We also recently approved the looping of an NGL pipeline upstream of our Lone Star Express Pipeline, which will expand our access to NGLs from the Northern Delaware Basin, where we see significant growth from our customers. Looping this pipe is expected to allow us to source an incremental 150,000 barrels per day of NGLs for transportation on our NGL pipeline system from this high-growth region. The project will cost approximately $60 million and is expected to be in service in the first half of 2027. Now turning to Lake Charles LNG. We continue to make substantial progress towards commercialization of this project. During the second quarter, Lake Charles LNG signed an HOA with MidOcean Energy, which provides a nonbinding framework for the joint development of the LNG project, with MidOcean entitled to receive 30% of the LNG production, approximately 5 million tonnes per annum. In addition, Lake Charles signed 20-year SPAs with Kyushu Electric Power Company and Chevron USA. On the marketing side, we are in advanced discussions with multiple parties for our remaining capacity and are getting close to our target of 15 million metric tonnes per annum. Some of our potential offtake customers are also interested in equity in the project, which if concluded, would reduce our external financing requirements. As we have previously stated, we expect to sell equity in the project to reduce Energy Transfer's ownership to approximately 25%. Over the last several months, we have been working with our financial advisers to finalize marketing materials as we prepare for the launch of the equity sell-down process. Now for a brief update around our new natural gas opportunities for new power plant and data center development. We continue to see a significant level of activity from demand pull customers to supply, store and transport natural gas for gas-fired power plants, data centers and industrial and onshore manufacturing. And we remain in advanced discussions with several facilities in close proximity to our footprint. We would expect these types of projects to generate revenue relatively quickly. Our team continues to do an excellent job of identifying the most likely opportunities, and we will continue to provide updates as we move forward. Lastly, construction of 8 10-megawatt natural gas-fired electric generation facility continues. The second facility, which is serving our Badger processing plant, was recently commissioned, and we expect 2 more facilities to be placed into service by the end of the year, with the remainder expected to be in service in 2026. Now turning to our guidance. We now expect to be at or slightly below the lower end of our guidance range of $16.1 billion and $16.5 billion. This is a result of weakness in the Bakken, slower recovery in the dry gas areas than we expected and a lack of normal volatility in our gas optimization business from spreads and storage margins. In addition, we expected stronger growth in our Permian crude business than we have seen year-to-date. In summary, given the substantial growth in demand for energy resources over the next several years driven by natural gas and natural gas liquids, we believe that Energy Transfer is the best positioned company in the industry to help meet this demand. We own one of the largest natural gas pipeline networks in the United States with physical assets in every major U.S. producing basin. We have more than 105,000 miles of natural gas pipelines that is coupled with significant gas storage, and we move approximately 30% of the U.S. natural gas production. We are connected to nearly 200 gas-fired power plants in the country and have the ability to leverage strong relationships to develop new projects backed by higher quality counterparties on both the supply and demand side. We offer significant optionality, including bidirectional pipeline flow capabilities and strategically located storage assets, helping secure stable, uninterrupted supply. In addition, our operations team has extensive experience managing pipelines and a long-term proven track record of delivering reliable energy for our customers even during extreme weather events. Building on our natural gas strategy, our Hugh Brinson and Desert Southwest pipeline projects and our Bethel storage expansion project further establish our natural gas pipeline business as the leading option for customers seeking dependable natural gas supply. In addition to numerous opportunities in natural gas, we have one of the largest NGL businesses in the United States with more than 1.4 million barrels per day of NGL export capacity, and we are continuing to expand this business to meet the international demand. We also continue to evaluate projects to expand our crude oil pipeline network. Our backlog of well-contracted growth projects is expected to generate strong returns, enhance our integrated value chain and promote strong growth well into the future. We have a strong track record of organic growth, which has been enhanced by our long history of successful acquisitions. Each of these acquisitions has added strategic benefits and critical mass, providing the incremental opportunities for continued growth of our nationwide network. This concludes our prepared remarks.

Our first question comes from Theresa Chen of Barclays.

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

Theresa, this is Mackie. Usually, I make a statement at the end, but I'll make a quick remark now and then answer your question as it ties in. Since Kelcy started this over 25 years ago, we began with a 10-inch pipeline in East Texas that was inactive, and we've grown significantly through acquisitions and major organic projects across the U.S. Looking at our team, both in the office and in the field, we face challenges that are unparalleled compared to our competitors. Despite this difficult quarter we're going to discuss, I believe everyone here shares my excitement about our position and the future of our industry and partnerships. Many factors drive this optimism, including your question. I've been advised to avoid making timelines too specific, so I will be cautious. Recently, data centers have emerged rapidly, presenting tremendous opportunities for companies like us with substantial pipelines in ideal locations for such projects. These projects are substantial, often costing between $50 billion to $100 billion, and they require significant time to develop. For example, the Desert Southwest announcement took 3.5 years to bring to fruition. To be careful in my estimates, I’ll just note that a few months ago, we signed a significant deal with a hyperscaler in Texas for 80,000 a day, which we have now increased to 380,000 a day, with potential to reach 475,000 or more from this area. This is just one of three deals we've signed in Texas, with two more close to being finalized and one significant deal in the works outside of Texas. However, I am not committing to specific timelines as each data center has unique needs and requirements. This particular deal progressed rapidly given our enthusiasm. We are also excited about the other opportunities we are pursuing, so without making any promises about new data centers or associated power plants, please stay tuned for announcements in the upcoming quarters.

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

So gosh, we haven't announced something in a while that is exciting as this. Beth Hickey and her team did an incredible job. This is just keeping your head to the grindstone for the last 2.5-plus years, very excited. We kept hearing about other projects, kind of ignored that, paid attention to what we do, and we're very excited. Yes, we haven't fully sold that out. We have 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 3 to 4 weeks of folks that aren't in heavy negotiation 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 that all on this call, but that's what we're going to do. But because of the enormous demand growth along this pipeline and in the Phoenix area, there's just some upside that's probably going to make sense, seriously looking at that. And if we do and get that going, we are confident that we'll sell that out. So yes, from the standpoint of returns, there's some upside that I kind of want to talk to about on this call, but 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 Tonet of JPMorgan.

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

Yes, this is Mackie again. Tom is here to provide any follow-up comments he wants to make. Raj is also here, and he has been closely involved with EPC contracts for a while. We had our own expectations while waiting for the incoming numbers, and they align perfectly with what we anticipated. We are definitely factoring in tariff changes, which seem to fluctuate daily. We're very pleased with how the EPC contract is shaping up; it's right in line with our expectations and fits well with what we've contracted and the ongoing contract. As Tom mentioned in the opening statements, we've been expressing our excitement about this for many years. We're pushing hard to reach the finish line and will do everything possible to achieve that, although there is still some work to be done. Nonetheless, there is significant interest in this project, and we believe we will progress over the next couple of months. After that, we plan to initiate the financing and move towards a final investment decision as quickly as possible.

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

This is Mackie again. We've closely examined the situation over the past year and a half. We expect to have no right of way issues across tribal lands, and based on our observations so far, we don't anticipate any challenges related to right of way. We plan to proactively communicate with FERC, the Department of Energy, and the Department of Interior, and we will engage in discussions with the governors of New Mexico, Arizona, and Texas. Our government relations team will be actively present in the counties affected in these three states. We have paid significant attention to this matter and have allocated contingencies for unforeseen circumstances. Overall, I'm very optimistic about our cost projections and confident that we will meet or come in under our current estimates.

Our next question comes from Keith Stanley of Wolfe Research.

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

Yes. That's a great question. I will refer back to my opening statement. We have excellent people and valuable assets. We were patient, as I mentioned, and took the time to rebuild. We've heard various rumors about other projects being on the verge of launching, but we chose to focus on our goals instead. Our main concern is reaching the finish line with our team, their negotiation skills, and the supply sources we provide. We're connected to major intrastate pipelines and many large cryogenic facilities. By integrating all these elements, we have been successful in leveraging synergistic benefits from the projects we complete. This, combined with our commitment to understanding and responding to customer needs and navigating tough negotiations, resulted in a fair deal overall. I believe our customer is very satisfied with our current position, and I want to commend Beth and her team for their exceptional engineering efforts and the support from many others in this office.

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

It's a traditional deal, which is our approach. We know some competitors take on projects and undercut the rates, but if costs rise, the rates will go up. This is how we've established our partnership. We invest significant effort into research, and we have skilled professionals handling our right-of-way estimations as well as pipeline and compression costs. As I mentioned earlier, we are confident about this. We have accounted for tariff costs and contingencies, and we feel good about it. Regarding the first part of your question, yes, a 6x multiple is a solid figure to consider.

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

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

Jean, this is Dylan. Good question. It's a bit of both. At the beginning of the year, we noticed slightly lower volume, some of which was a carryover from the fourth quarter. We had anticipated growth, but it hasn't materialized as we expected. However, we are still experiencing strong volumes in most areas, just not at the growth rate we had forecasted. Looking toward the latter half of the year, we anticipate some growth, but we have some catching up to do to reach our expectations for this time of year. So, as I mentioned, it's a little bit of both for the year.

Yes, I’d like to add that we are very optimistic about Bakken. It may seem surprising given our challenges in the second quarter, but there are many positive developments underway. The TMX expansion project started about a year ago, which has enabled us to transport crude oil to refineries and export it to Asia. This has reduced the volume of Canadian barrels, opening up some pipeline capacity from Canada that can now be utilized. With a competitor reducing their Bakken output, this capacity will diminish in the next 1.5 to 2 years, allowing demand from Canada to fill that gap. In terms of quarterly performance, we experienced a decrease in volumes due to cold weather in April and May, which led to slowed completions and some deferments and curtailments, resulting in about 50,000 fewer barrels per day in the second quarter. Additionally, fires impacted the movement of barrels through both TMX projects, causing refineries in Canada and the Northwestern U.S. to pay a premium for oil since they were short on supply. While this boosted our business through rail terminals, it did reduce some pipeline volumes, which are expected to recover. When we consider all of this, there are around 80,000 to 120,000 barrels that have been in flux or not produced, but those will be reintroduced into the system. Moreover, we are particularly excited about the open season with Enbridge. Our team has done a great job leveraging our assets—shifting a natural gas pipeline to a crude line to facilitate Bakken transport to the Gulf Coast, converting an interstate pipeline in West Texas and Mexico to NGL, and another pipeline to diesel. We continually assess how to keep our pipelines fully utilized now and for the next 10 to 15 years.

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

Yes. Our ninth frac's coming on at the end of next year so that kind of plays a role in all of this. We've got to have a home for it. But yes, we're right on target. As Tom mentioned in the opening statements, we're bringing these cryos up to Lenorah II. 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 cryos. 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.

Our next question comes from Gabe Moreen of Mizuho.

I wanted to ask about the ethane export issue from some time ago. Did it have any impact on your quarterly results? Also, looking at the bigger picture, as you consider your expansions and other projects, has it changed your plans regarding the markets you might target for ethane or ethylene exports, and how do you see the commercial future for that?

Yes. Regarding the first part of your question, there was no impact. Fortunately, it didn't last long enough to affect us. We weren't worried about it. The only effect I would mention is that international companies have relied on doing business with the U.S., which has traditionally honored such agreements. So this situation tarnished our reputation a bit, as well as that of our industry and country, especially since we had contracts and significant investments in crackers, particularly in China, with a strong partner in satellites. It wasn't easy, but we managed to get through it. Thankfully, that issue has now resolved. We anticipate that it may be somewhat more challenging to contract with Chinese crackers moving forward, as they might become more cautious. In response to your question, we are actively exploring other countries and companies as we always have, and there are plenty of opportunities out there. We are optimistic and believe that further expansions will occur, needing to take place at both Marcus Hook and Nederland. However, the recent ethane situation did slow down progress 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 can you just maybe give us some more color in terms of what those hydraulics kind of do for the project and what sort of demand you're looking to meet there with that?

We've been really excited about the Desert Southwest project, but we are even more enthusiastic about the Hugh Brinson project. The timing couldn't have been better. Although we've missed several projects in the past, we finally achieved the necessary rate of returns on this project as we brought it to completion. There is tremendous interest in it, and we have no intention of selling it off, as we are considering the next stages. By incorporating the bidirectional capability, we can offer additional supply sources for our Texas markets, which significantly enhances its revenue potential and improves the rate of return beyond our initial expectations. As I mentioned earlier, while we find all our international assets thrilling, the opportunities in Texas are particularly compelling. If you're looking to build a data center in Texas, Energy Transfer stands out as the best choice, considering our extensive pipeline infrastructure and storage support that allow us to deliver when it’s most needed. We are very optimistic about this, and we believe that the Hugh Brinson project will be a valuable asset for us for many years to come. We are fortunate to have launched it at the right time.

Our next question comes from Manav Gupta of UBS.

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

Yes, it's reasonable to think that figure will increase. There is still a lot of time and numerous projects the team is working on, with some exciting developments ahead. We expect to share a variety of announcements over the next couple of years. For now, I believe that number will trend significantly higher than what's currently projected, especially with the Desert Southwest project.

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

Yes, this is Mackie again. Yes, as we've mentioned over the years, we're very excited about LNG. But what really drives us on LNG is the pipeline transportation business that we're so good at and that's what 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.

Our next question comes from Michael Blum of Wells Fargo.

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

What we plan to do is move forward with financing once we have signed either SPAs or HOAs, or a combination of both. The HOAs are practically binding, even if they aren't officially. Once we sign the SPA, we are very confident we will reach an HOA, and after signing the HOA, we believe we can achieve the SPA in a relatively short 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 just wanted to get a sense for the cadence beyond this year.

Michael, this is Tom. I know Dylan touched on this earlier, but I want to provide some clarity. We're experiencing growth with several exciting projects and expect to offer more guidance later this year. Typically, we share guidance for 2026 during the year-end earnings call. However, given the numerous promising projects we have currently, including the Desert Southwest and Hugh Brinson, we'll need a little more time before we can provide detailed updates. Once Lake Charles gets underway, we’ll incorporate that into our plans as well. Just bear with us as we navigate these developments, but you can definitely expect positive progress.

Our next question comes from Zack Van Everen of TPH.

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

Yes, this is Mackie. It's probably a little early to provide that level of detail. The reason is that some projects may be a mile or two away while others could be as far as 25 miles. Generally, they are much closer to our systems, but there will be an additional fee associated with that. I would say that as we complete more of these projects, they will have a significant impact on our EBITDA, with each project contributing differently. Some will have a much higher EBITDA impact than others. However, I don’t think we can quantify that exactly on this call, but we are very optimistic about the direction this business is heading.

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

It will be incremental growth. As Badger ramps up, we are running out of capacity as we have more growth in the Southern Delaware and New Mexico. We expect growth from existing contracts, new growth from our processing plants that are coming online, as well as third-party processing plants that our NGL team is actively negotiating with.

Our final question comes from John Mackay of Goldman Sachs. It will be incremental growth. As Badger ramps up, we're running out of capacity where we've got more growth up in the Southern Delaware and New Mexico. So we expect growth from existing contracts, new growth from our processing plants that are coming online, as well as from third-party processing plants that our NGL team is actively negotiating with.

I think Manav asked this one way, but I might ask it in 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?

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

Sorry, I guess, percentage of total ET EBITDA.

I don't think we can provide an exact number at this time. As you mentioned, there are many projects underway and numerous growth opportunities across all our segments. Currently, the two major expansion projects, Hugh Brinson in intrastate and Desert Southwest in interstate, are expected to grow as a share of the overall business, likely at the fastest rate compared to our other segments in the future.

Are you in a position to discuss a potential EBITDA growth rate target moving forward, or something along those lines, perhaps a framework or general target, even if it's not exact guidance?

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

I want to reiterate something we've mentioned publicly: our goal for distribution growth is between 3% to 5%. This range is intended to set a minimum threshold for our expectations regarding long-term growth in distributable cash flow per unit. We are not looking to artificially create growth in distributions by adjusting our coverage. This figure serves as the baseline for our long-term growth rate.

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

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

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