Earnings Call Transcript - ET Q4 2025

Operator, Operator

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

Thomas Long, Co-CEO

Thank you, operator, and good morning, everyone, and welcome to the Energy Transfer Fourth Quarter 2025 Earnings Call. I'm also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this morning. As a reminder, our earnings release contains an update to guidance and a thorough MD&A that goes through the segment results in detail, and we encourage everyone to look at the release, as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more details in our Form 10-K for the year ended December 31, 2025, which we expect to file later this week. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Let's start today with the financial results for full year 2025. Adjusted EBITDA was nearly $16 billion compared to $15.5 billion for 2024. This was up 3% over last year and was a partnership record. DCF attributable to the partners of Energy Transfer, as adjusted, was $8.2 billion compared to $8.4 billion for last year. Operationally, we moved record volumes across each of our interstate midstream NGL and crude segments for the year ended 2025. We also exported a record amount of total NGLs out of our Nederland and Marcus Hook terminals. For the fourth quarter of 2025, we generated adjusted EBITDA of approximately $4.2 billion compared to approximately $3.9 billion for the fourth quarter of last year. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2 billion, consistent with the fourth quarter of 2024. During the quarter, we recorded records in each of our NGL fractionation throughput, LPG exports, Nederland terminal volumes and crude transportation throughput. And for full year 2025, we spent approximately $4.5 billion on organic growth capital, primarily in the NGL and refined products, midstream and intrastate segments, excluding SUN and USA compression CapEx. Turning to our results by segment for the fourth quarter, and we'll start with the NGL and refined products. Adjusted EBITDA was $1.1 billion, consistent with the fourth quarter of 2024. We saw higher throughput across our Gulf Coast and Mariner East pipeline operations, Mont Belvieu fractionators and Nederland terminal. Results for the quarter included a one-time $56 million increase from a regulatory order impacting prior and current period rates. These were offset by $58 million of lower gains related to the timing of the settlement of NGL and refined products inventory hedges, which we anticipate will be recognized during the first quarter of 2026. In addition, loading delays related to fog at Nederland resulted in a $14 million impact, which we are on track to make up in the first quarter of 2026. For midstream, adjusted EBITDA was $720 million compared to $705 million for the fourth quarter of 2024. This was primarily due to volume growth in the Permian, Northeast and ArkLaTex regions. Results were partially offset by a one-time expense increase of $14 million in intersegment NGL transportation fees as a result of the previously mentioned regulatory order. For the crude oil segment, adjusted EBITDA was $722 million compared to $760 million for the fourth quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems and our Permian Basin gathering system. Results also included a one-time $19 million increase related to the previously mentioned regulatory order. These were offset by lower transportation revenues, primarily on the Bakken pipeline. In our interstate natural gas segment, adjusted EBITDA was $523 million compared to $493 million for the fourth quarter of last year. This increase was primarily due to more capacity sold and higher utilization on several of our pipelines, including Panhandle Eastern, Trunkline, Florida Gas and Transwestern. And for our intrastate natural gas segment, adjusted EBITDA was $355 million compared to $263 million in the fourth quarter of last year. This increase was primarily due to increased pipeline and storage optimization, as well as increased volumes across our Texas intrastate pipeline system due to third-party volume growth. Now turning to our organic capital guidance. As we previously announced, our 2026 organic growth capital guidance range is projected to be between $5 billion and $5.5 billion, excluding SUN and USA Compression. We expect approximately two-thirds of this capital to be invested in projects that will enhance our natural gas assets, including the Hugh Brinson and Desert Southwest pipeline projects, Mustang Draw I and II, as well as continued system build-out in the Permian Basin. In addition, approximately one-fourth of the growth capital will be in the NGL and refined products segment related to the ongoing construction of the Nederland and Marcus Hook terminal expansions as well as Frac IX and Mont Belvieu. These expansions are contracted under long-term commitments and are expected to generate mid-teen returns and considerable earnings growth over the next decade or more. Beyond these projects, we have a significant backlog of opportunities that are expected to support continued growth. For a closer look at some of our major growth projects, I'll start with the natural gas side of our business, where we continue to see significant demand for our services. In December, we announced that we have upsized the mainline pipeline diameter for Desert Southwest Pipeline Project from 42 inches to 48 inches to meet the planned and anticipated customer demand. This will increase the project's capacity to up to 2.3 Bcf per day. A full buildout of the project is expected to cost approximately $5.6 billion, and we continue to expect the project to be in service by the fourth quarter of 2029. Our teams continue to actively engage with elected officials, county leadership and associated communities along the rail to communicate project information and updates, and we have engaged with over 275 stakeholders to date. Our discussions have been very positive, and existing and potential stakeholders are pleased about the economic benefits expected and also realize the critical need for a substantial, reliable supply of gas to help address the significant demand growth in Arizona and the Mexico market. Next, construction of our Hugh Brinson pipeline is going well. As of today, 100% of the 42-inch pipe has been delivered to our pipe yards, and mainline construction of the pipeline is approximately 75% complete. We expect Phase 1 to be in service in the fourth quarter of this year. However, if we stay on our current schedule, we should have the ability to flow some early volumes prior to Phase 1 in service. And we continue to expect Phase 2 to be in service in the first quarter of 2027. As a reminder, this system will be bidirectional, with the ability to transport approximately 2.2 Bcf per day from West to East and approximately 1 Bcf per day from East to West. The pipe is fully contracted from West to East, and we also have a growing amount of volume committed on backhaul that is expected to add significant upside with no additional capital. On Florida Gas Transmission, or FGT, we recently completed open seasons for two new projects that are supported by long-term binding agreements from anchor shippers. The Phase IX project, which is designed to expand firm natural gas transportation capacity to multiple new and existing meter stations located across FGT's market area. This project will consist of the construction of up to 82 miles of pipeline looping, as well as new and upgraded compression. This would expand FGT's capacity by up to 550 million cubic feet per day. The project is expected to be available for service in the fourth quarter of 2028. The South Florida Project is designed to enhance the reliability of critical infrastructure and increase overall deliveries in South Florida. It will consist of the construction of a new 37-mile lateral to supply the South Florida area, along with compression in a new meter station. The project is expected to be available for service in the first quarter of 2030. Energy Transfer's share of the cost of these two projects is expected to be up to $535 million and $110 million, respectively, depending on the final shipper volume elections. And construction of a new storage cavern at our Bethel natural gas storage facility, which is expected to double our working gas storage capacity at the facility to over 12 Bcf, remains on schedule to be in service in late 2028. Now for a brief update around recent natural gas opportunities for new power plant and data center development. On our last call, we announced we have long-term agreements with Oracle to deliver approximately 900,000 Mcf per day of natural gas to three U.S. data centers. We recently began flowing gas on the first pipeline lateral to a data center campus near Abilene, Texas. Two more laterals are expected to be completed in mid-2026. Supply for all three of these pipelines will be sourced from our Hugh Brinson and North Texas pipelines. As a reminder, Energy Transfer has entered into a 20-year binding agreement with Entergy Louisiana to provide at least 250,000 MMBtus per day of firm transportation service to fuel their facilities in Richland Parish, Louisiana. Within the last year, we have contracted over 6 Bcf per day of pipeline capacity with demand-pull customers. This includes volumes from end users, data centers and utilities off of Desert Southwest, Hugh Brinson pipelines and other of our natural gas pipeline systems. And we remain in advanced discussions with several other facilities in close proximity to our footprint. Our Oklahoma intrastate power team recently added connections to serve three new power plant loads in the state of Oklahoma, totaling approximately 190 million cubic feet per day. These are expected to come online in the second quarter of 2026. These connections are supported by long-term contracts with investment-grade counterparties. In addition, we have also entered into advanced negotiations to serve another 350 million cubic feet per day of new power plant demand in Oklahoma. Outside of Oklahoma and Texas, our team continues to work on multiple transactions with power plants to provide significant transportation revenue across 13 other states, which have a high likelihood of reaching FID. Lastly, construction of a 10-megawatt natural gas-fired electric generation facility continues, and we expect our third facility, which will be located at our Grey Wolf processing plant, to be in service in the first quarter of 2026. The remaining five facilities are expected to be fully constructed and ready for service later this year. Now looking at the Permian processing expansions. We continue to expect our Mustang Draw I and II plants to be in service in the second quarter and fourth quarter of this year, respectively. At our Nederland terminal, volumes on our Flexport NGL export expansion project have continued to ramp up, and we exported our first two ethylene cargoes in December of 2025. This contributed to record exports out of Nederland for the fourth quarter of 2025. We continue to work with Enbridge on a project to provide capacity for approximately 250,000 barrels per day of light Canadian crude oil through our Dakota Access pipeline, and we expect to take FID on this project by mid-2026. Turning to Lake Charles LNG. In December, we announced that we suspended the development of this project. As we have previously stated, we continue to be extremely focused on capital discipline, and we have directed our efforts toward our significant backlog of projects that we believe provide a more attractive risk/return profile. However, we remain open to discussions with third parties who may have an interest in developing the project as we would expect to benefit from providing natural gas transportation capacity for the project. We're also exploring other projects to better utilize the terminal in a more profitable way. Turning to our guidance. We now expect our 2026 adjusted EBITDA to range between $17.45 billion and $17.85 billion compared to the previous range of between $17.3 billion and $17.7 billion. This change in guidance is solely attributable to the USA Compression's acquisition of J-W Power Company, which closed on January 12, 2026. Looking ahead, we are poised for continued growth in 2026, driven largely by the ramp-up of our Flexport NGL export project, new Permian processing plants and other projects. We believe our Hugh Brinson pipeline, which is expected online later this year, is extremely well positioned to become a major U.S. header system that ties together with our network of large diameter pipelines and allows us the flexibility to deliver natural gas from Texas to the Desert Southwest, Southern Florida, the Midwest and anywhere in between. In addition to our extensive pipeline systems, we have over 230 Bcf of storage to support the market demands of our customers. This shift provides significant upside in the future and further establishes Energy Transfer's natural gas pipeline business as the premier option for customers seeking dependable natural gas supply. We are currently undertaking a large slate of growth projects, including projects that will help address the need for reliable natural gas solutions to support power plant and data center growth plans, as well as the growing international demand for natural gas liquids. As a result, project execution remains one of our top priorities for 2026, and we will continue to place a significant amount of focus on completing projects safely, on time and on budget. We also continue to see new growth opportunities across all aspects of our business and are extremely well positioned to help meet the substantial growth in demand for energy resources over the next several years. Given our extensive backlog of potential growth projects, we continue to be extremely focused on capital discipline, and we'll continue to target projects that are expected to generate the highest returns while balancing project risk. We continue to target a long-term annual distribution growth rate of 3% to 5%. We also expect to maintain our leverage target of 4x to 4.5x EBITDA during this period of meaningful investment opportunities. In summary, our extensive asset base and diverse product offerings is allowing us to deploy capital across our footprint. With several major growth projects coming online over the next several years, we continue to have great visibility into our ability to grow our franchise for many years to come. This concludes our prepared remarks. Operator, please open the line up for our first question.

Operator, Operator

The first question comes from Theresa Chen with Barclays.

Theresa Chen, Analyst

It's encouraging to see the continued commercialization momentum across your natural gas asset base. Could you talk about the key drivers behind the progress today? And maybe talk about some of your more creative solutions to address market needs, maybe with Hugh Brinson as an example in the multiple life of service and revenue opportunities on that system? And as you look ahead, where do you see the next set of commercialization or optimization opportunities, whether through new customers or end markets or further integration across your footprint?

Marshall McCrea, Co-CEO

Hello, this is Mackie. Thanks, Theresa. Listening to Tom's opening statement, it's hard not to feel excited. We're thrilled about the future of our DSW project, a 500-mile 48-inch pipeline, the largest of its kind ever built in the U.S. Then there's our Florida Gas pipeline system, which is due for another expansion. During the open season, we saw more interest than we expected, so we foresee another expansion in Florida soon. This pipeline constantly provides value. As Tom mentioned, we have a key asset in the middle of our system with Hugh Brinson, which allows us to transport significant volumes from west to east and vice versa, plus it enables us to source gas from virtually any basin globally to supply markets along our system, including the Gulf Coast and Southeast. We're very enthusiastic about the assets we've developed. Regarding commercialization, we are expanding our cryogenic facilities this next quarter and in the fourth quarter in the Permian Basin, the most productive area in the U.S., which connects to our NGL system. We have an NGL transportation expansion planned for midyear, leading into our frac that will launch in the fourth quarter, which supports the Flexport expansion we just completed for 2025. The future of our NGL business in Texas and beyond looks promising. We're enhancing our Marcus Hook ethane capabilities for exports, and we are the largest transporters of NGLs in the Northeast, anticipating continued growth for our partnership. Additionally, the assets and demand around our pipelines extend beyond data centers. We're pursuing power plants to support electricity needs for data centers, population growth, and manufacturing facilities. The power plants Tom mentioned in Oklahoma were primarily developed for population and manufacturing growth, rather than data centers. We are extremely enthusiastic about our geographic footprint and are optimistic about our prospects over the next 10 to 15 years due to our asset base across the United States.

Theresa Chen, Analyst

And then maybe just a follow-up on the NGL front, understanding that you have a significant amount of organic growth ahead of you with your infrastructure in flight. Just with some of your Permian NGL competitors bringing online downstream assets recently and through the year and moving their own volumes back onto their own systems as a result. Can you remind us how much third-party downstream Permian Y-grade volumes you have across your system as a mix of total volumes at this point? How much Y-grade do you transport and frac at this point that doesn't come from your own processing?

Marshall McCrea, Co-CEO

Yes. Maybe Dylan can follow up with the exact percentage, but the majority of our gas, more than half is coming from our own facilities. We just talked about the two Mustang Draw, both of those together, 550,000 Mcf a day, that's approaching 85,000 to 90,000 barrels alone just from our own cryos. And as we ramp up the rest of our cryos, we've got a lot of additional equity-owned liquids that we will be feeding into our massive intrastate transportation fracking and export business. I don't know the exact percentage.

Dylan Bramhall, CFO

We are currently sourcing about 60% of our volumes from our own facilities and 40% from third parties, with the affiliate volume number continuing to increase. As we progress through the year, we expect that 60% to rise further.

Operator, Operator

The next question comes from Gabe Moreen with Mizuho.

Gabriel Moreen, Analyst

Could you provide an update on the conversion of a pipeline from NGL to gas service? I don't think this was mentioned in your opening remarks.

Marshall McCrea, Co-CEO

This is Mackie again. Let me kind of step back a little bit. Energy Transfer had a strategy since the day we began of looking at every asset we own and can we use it in a more profitable, efficient manner. So that's an ongoing thing that always happens with us. We've converted a natural gas pipeline to crude oil and moving Bakken down to the Gulf Coast. We've converted a liquid line to diesel and moving diesel from the Gulf Coast to the Permian Basin. We've converted a TW line to NGLs. So it's just kind of on and on. So that's just a process we go through. We evaluated that what we've looked at now though is with the growth in the NGLs, both as Dylan just talked about, not only in our systems, but also barrels that we're chasing on third-party systems. We can't afford to take that business. We're going to fill up that NGL pipeline. And if we need to loop another pipeline west to Eastern Texas, that will be a new project for natural gas.

Gabriel Moreen, Analyst

I appreciate that. And then maybe if you can just talk a little bit broadly about how your assets performed during some of the winter weather we've been having and the volatility in the gas market? And also to what extent that may or may not have benefited you guys financially here in the first quarter?

Marshall McCrea, Co-CEO

Yes. With Tom's leadership and Greg and Daniel and getting our operations team not only offer our assets safely, efficiently and profitably, but we also pride ourselves on times like this when it's critical to move energy to the market and create, in this case, electricity in tough times. We proved ourselves during Uri, paid off in a big way. The same way this last storm that came in, in January, we were prepared as good as we could be. The negative, positive, however you want to look at it is that the industry got prepared. They saw what happens if you have an asset that are prepared, they're line-pack storage. You've got people manned out on your facilities. You can keep gas flowing as much as possible, and you can make a lot of money in those opportunities. So with the industry being, I think, much more prepared, all of us got through that better. We did see volumes come off, like they always do with freeze-offs in the Permian Basin. We were able to keep all of our customers whole to our pipeline systems as well as coming out of storage. So yes, we didn't see the type of profits and earnings that we saw a number of years ago with Uri. But as we always do, our team performed excellently during that very cold day period in Texas and throughout the country.

Operator, Operator

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

Jean Ann Salisbury, Analyst

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

Marshall McCrea, Co-CEO

Yes, this is Mackie again. First of all, I want to emphasize that we have an excellent engineering and construction team, likely the best in the country, as we develop these assets. We are making significant progress ahead of schedule on Hugh Brinson. However, we will proceed cautiously because uncertainties remain regarding when volumes will come online. Currently, we believe we can start bringing on some volumes earlier than the fourth quarter, and we will manage this in accordance with our contractual and regulatory obligations. Our goal is to secure new egress out of the Permian Basin, which is essential for the producers facing negative pricing issues at Waha. This will provide a substantial boost, not just for our assets but also for the entire Permian Basin. We will have more information to discuss in the next earnings call regarding potential volumes and timing, but right now, we anticipate having some early volumes in the fourth quarter, though we cannot specify exactly when or how much.

Jean Ann Salisbury, Analyst

That makes sense. And how do you think about what the limit is for how much Canadian heavy crude could eventually run on the DAPL asset? If Bakken crude production does fall off over the next 5 to 10 years, is there any technical limit to how much the DAPL system could switch over to running Canadian heavy and set?

Adam Arthur, Executive

Jean Ann, this is Adam. So as we're talking about MLO 2, which I think is what you're referring to, we've definitely done a look. And first and foremost, we're going to make sure that we take care of our Bakken producers and make sure that they can all move their oil out of that basin. . But as you mentioned, as we see Bakken volumes kind of steady off and maybe potentially decline in the future, there's a number of different possibilities on moving additional volumes through DAPL. Right now, the project's scope to move 250,000 barrels a day of light volumes down kind of off the Enbridge mainline system through DAPL and into Patoka to deliver back to them there. But we're definitely looking, and I think Enbridge even alluded to it some on their call about additional opportunities down the road as we see Bakken volumes potentially decline.

Operator, Operator

The next question comes from Keith Stanley with Wolfe Research.

Keith Stanley, Analyst

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

Dylan Bramhall, CFO

Keith, this is Dylan. Let us answer the question this way. But when we set our long-term distribution growth rate of 3% to 5% annually, that was very strategically set. That's not meant to be a manufactured growth rate. That's really driven from eating into coverage. But we said that, that basically sets the floor for what we believe we can achieve for our long-term growth rate.

Keith Stanley, Analyst

Got it. That's helpful. Regarding Texas NGL recontracting or contract expirations, how should we view recontracting on the Mariner system? I believe some contracts will expire in a few years as well. Do you anticipate pricing improvements or declines there? Additionally, how does the Mariner system compare to other NGL takeaway options available for producers?

Marshall McCrea, Co-CEO

This is Mackie again. Yes, we have an incredible set of assets. We have built a franchise with our Mariner pipelines going west, and the majority also going east. We are expanding our ethane export capabilities out of Marcus Hook. We believe this system will continue to perform. While we won't discuss specific strategies regarding contract expirations and renegotiations, we are very confident that we will maintain our current volume throughput and that we will have opportunities to grow from there. This is a strong business for us, and we will keep looking for ways to expand and maintain our leadership in transporting natural gas liquids out of the Marcellus and Utica regions.

Operator, Operator

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

Julien Dumoulin-Smith, Analyst

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

Marshall McCrea, Co-CEO

You bet. This is Mackie. I'll address the Desert Southwest, and then Adam can follow up on the DAPL question. I want to reiterate how excited I am, and the executive team is, about what we've built and the strong position we hold in the country. Moving more gas toward Phoenix is significant. Some larger players are projecting growth between 25 and 35 gigawatts beyond current needs, which is more gas than our 48-inch pipeline can handle. Regarding returns, I want to manage expectations. However, we believe this type of project will likely be one of our best in terms of return on investment due to its one-way flow. We often mention that Hugh Brinson will generate revenue from multiple directions, but transporting natural gas from New Mexico to markets in Southern New Mexico and the rapidly growing population centers, including data centers in Phoenix, will make this one of our top projects in a long time.

Adam Arthur, Executive

Julien, this is Adam. So we just closed on an open season on DAPL, and we're really happy with the result. We were able to actually add some incremental volume, but not only add incremental volume, get some of our base customers extended out well beyond kind of the mid-2030s. And we did that at rates that were good, what we believe good market rates reflective of the value of the assets. And so as we kind of tie the MLO 2 conversation in with that, we expect those rates to be in line with the rates that we're seeing from the Bakken producers in the basin.

Julien Dumoulin-Smith, Analyst

Yes. I hear it. Mackie, just quick super quick on that expansion and further upside on DSW. I mean, it looks like even next year, we could get some real clarity on the 25-plus that you alluded to a second ago. I mean, the scope seems pretty real-time that we're going to get that expansion in capacity through the IRP processes. Do you think we could be talking about a further expansion of DSW in some form or fashion here in even the next 12 months? I know you guys just did it here, but not being facetious.

Marshall McCrea, Co-CEO

We love your thinking. If there's an opportunity to build more pipe, we certainly will do that. I guess I would think about it this way. We own Florida Gas Transmission. We continue to look at that pipeline. We've got gas coming into Florida Gas on the East moving back into Texas. We've got gas coming to Louisiana, moving to Texas. And I can go on and on, but we have multiple pipelines in those ditches. We're adding our Phase IX. Very likely, we'll add Phase X at some point in the future. Do we see Desert Southwest being a similar opportunity? Absolutely. As New Mexico grows and as Phoenix area grows with demand for natural gas for a number of reasons, there's certainly going to be opportunities to look at compression, backhaul. Who knows what the future holds, but we certainly will look forward to any of those opportunities on adding additional assets to deliver gas to those markets.

Operator, Operator

The next question comes from John Mackay with Goldman Sachs.

John Mackay, Analyst

Why don't we stay on DSW? You mentioned that you upsized and kept your timeline intact. Can you remind us when you need to make a decision on sizing? Additionally, as you work toward coming online by the end of the decade, what are the key milestones we should monitor as you execute?

Marshall McCrea, Co-CEO

Yes. I'll say once again, our E&C team is so good. On all these projects, we try to look ahead in the marketplace today, you can really get caught off guard. If you don't order steel, when you price it to your customers, you don't order compression, both from not only a pricing standpoint, but also a delivery standpoint. Mike Morgan and his team did a great job working with Beth on the timing. So we got way ahead of that. We actually secured 42-inch with the option to go to 48-inch in the first part of December. We exercised that option. So that is officially, of course, upsized to a 48-inch. We've already ordered all of that pipe, and we've already ordered all the compression to move the full 2.3 Bcf a day.

John Mackay, Analyst

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

Marshall McCrea, Co-CEO

Yes, we are ahead of schedule. Our customers are requesting weekly and monthly updates, and we are following through on that diligently. As mentioned earlier, we have reached out to local, state, and federal stakeholders throughout the process. A significant portion of the right-of-way has already been surveyed or approved for surveying. Much of this is situated within the existing pipeline and utility corridors, making it an advantageous area for our project. Currently, our worst-case scenario is that we will be completed by the fourth quarter of 2029, although we will strive to improve upon that timeline, as we have with other projects. Everything is progressing as planned.

John Mackay, Analyst

Okay. I have a quick follow-up regarding Lake Charles. You mentioned several options now that your specific project has been suspended. Could you share more about what those options might look like?

Marshall McCrea, Co-CEO

Yes, as we mentioned earlier, our strategy in transport involves evaluating all of our assets, not just our pipeline assets but also our terminals. Regarding Lake Charles, it seems we will not be moving forward as the lead. We will see if another party steps in to build a pipeline on our terminal. In the meantime, we are exploring various options without restrictions. This could include NGLs, a crude oil terminal, or accommodating other commodities. We'll see how it develops. We are certainly considering all of our assets, and the location is excellent with a good draft and terminal, so we expect it to generate business in the future.

Operator, Operator

The next question comes from Manav Gupta with UBS.

Manav Gupta, Analyst

You are clearly leading the way in securing partnerships with data centers. There is a significant emphasis on pipeline infrastructure, and you possess some of the top offerings in that area. I would like to discuss the storage opportunities further. These data centers require nearly full utilization. Could you elaborate on how ET could capitalize on the various storage opportunities that will emerge as you expand these data centers alongside the pipelines you are developing for them?

Marshall McCrea, Co-CEO

You bet. I want to commend Adam and his team for their efforts in Texas and other states. Additionally, Beth and her team are making great strides in other regions with data centers. There are even some producers interested in supplying gas to data centers, but the ability to do so depends on owning large diameter pipelines and having access to storage. We have excelled in public opportunities and are pursuing others to ensure reliable transportation through our extensive pipeline network across the country. As mentioned earlier, we have more than 230 Bcf of storage, and we are currently expanding that capacity to provide the nearly full reliability that these data centers require.

Manav Gupta, Analyst

Perfect. My quick follow-up is you mentioned, obviously, Oracle. Obviously, you're dealing with Fermi and Entergy. And so both those companies are indicating a much stronger demand. And I'm just trying to understand if they do decide to upsize their orders and want significantly more gas from you, would you be in a position to supply them with a lot more gas than what you have currently signed them on for?

Marshall McCrea, Co-CEO

Yes, this is Mackie again. Absolutely. Wherever there is a need for natural gas supply, there is no company in the country with capabilities and a footprint comparable to ours. Our data team created a map displaying all the fiber optic systems across the country, as well as the electric transmission system. It's interesting that we can almost align our pipelines with many of those corridors. We are extremely well positioned with our large 42-inch pipeline systems throughout the country, especially in Texas and states like Louisiana. No one is better positioned than we are. We can increase capacity, loop, add compression, and meet any natural gas demands along our systems.

Operator, Operator

The next question comes from Michael Blum with Wells Fargo.

Michael Blum, Analyst

I wanted to ask about Waha. Pricing has been very negatively volatile in the fourth quarter and is expected to remain affected in the first quarter due to the storm. Can you remind us how much open capacity you have to take advantage of spreads there? I know you've also increased that capacity recently.

Marshall McCrea, Co-CEO

Yes. Unfortunately, or fortunately, we have turned up a lot of that lately. That's what helped us get Hugh Brinson and other projects done. That's just the nature of the business. But we still have about 160,000 Mcf a day that we're benefiting from wherever the spread is from a day-to-day basis. And we're pretty excited about Hugh Brinson coming on, really opening up the basin for everybody and really to benefit the producers.

Michael Blum, Analyst

Got it. You and your competitors are all expanding frac capacity at Belvieu. I'm curious if you're seeing any change in rates for fractionation with all this new capacity expected to enter the market.

Marshall McCrea, Co-CEO

Yes. Among all our segments, the NGL transportation and fracking segment is currently the most competitive. There appears to be an oversupply developing in NGL transportation, though it's unclear about fracking. However, we focus on our own operations rather than worrying about what competitors are doing. Our priority is to build assets, keep them operational, and maintain high utilization rates. We're optimistic about filling up our natural gas transportation and increasing our Frac IX capacity as we plan to bring it online at the end of this year.

Operator, Operator

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

Elvira Scotto, Analyst

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

Thomas Long, Co-CEO

Yes, Elvira, thank you for that. Clearly, when we look at all the projects we've been discussing, there are many more in the pipeline that we are considering. It's challenging to provide specific growth guidance, but we've mentioned an early projection of 5 to 5.5. Given everything we're discussing, we believe it will remain quite strong. While it may be a bit premature to offer that guidance, we certainly have a number of promising projects to evaluate. Dylan, do you want to add anything further?

Dylan Bramhall, CFO

Sure, Elvira. One thing as we look out, one thing to remember is when we talk about our growth capital, growth capital guidance that we put out for this year, we're not as concerned about cash flow and staying within cash flow there. When we look at long term, we're really governing this is staying within leverage targets. So as you look out, we have strong growth coming on from a lot of assets going in service over the next couple of years, and that definitely creates more debt capacity for us. And so I think we're really set up well to be able to fund whatever Mackie and the team put together here over the next few years and this great opportunity set that we have in front of us.

Adam Arthur, Executive

Yes. So I'll let Enbridge kind of comment on what is required on their side. But from our perspective, we're ready. We've got the design, the systems in place. And there's a little bit of work we need to do, obviously, to make this work. But we're just in the commercialization phase. So continuing to have discussions, productive discussions with customers in Canada.

Operator, Operator

The next question comes from Zach Van Everen with TPH.

Zackery Van Everen, Analyst

Maybe starting on the Oracle data center. Can you talk to how much gas is flowing today and what the capacity is on those legacy pipelines before Hugh Brinson gets online?

Marshall McCrea, Co-CEO

Yes. This is Mackie again. But that is kind of confidential. We're not going to really share a lot of that exact volume flow at this time. But we are connected to our North Texas pipeline. We will be connected to Hugh Brinson in the Abilene area by about the middle of the year. So we're well positioned to be able to provide whatever gas supplies that they will need as they build out their data center.

Zackery Van Everen, Analyst

You mentioned the increasing number of backhaul contracts being signed. In your opinion, how much gas do you anticipate will actually reach Carthage, if any? Do you believe that most of it will be utilized in the Dallas and Abilene area?

Marshall McCrea, Co-CEO

Gosh, if we had that crystal ball, we'd certainly think differently about different pipes and stuff. But who knows? As we think about it, there's going to be 10 or 11 Bcf of new pipeline capacity built out of the Permian. There's several 48-inch pipes and 42-inch pipes being built out of Katy over into Louisiana. We've got a bunch of pipes in North Louisiana heading south, and we have a ton of pipes with capacity. So who knows where the pinch points will be. But the message really from us is this. There's nobody who can predict an answer to that question. Where most of the gas can be, where is the least. But what we can do is take the least priced gas and transport it to the market that's most needed in most areas of the United States. So we love the position we're in, and we'll be able to capitalize on whatever dynamics happened on the production front and the ebbs and flows from Permian Basin to East Texas to Haynesville. We just love the position we're in, not knowing exactly where all this is headed.

Operator, Operator

The next question comes from Jason Gabelman with TD Cowen.

Jason Gabelman, Analyst

You've mentioned potential to FID or a high likelihood of FID-ing projects across 13 states related to power. That obviously sounds like a high number on the surface. So wondering if you could give us a flavor of what those projects look like if they're more like CloudBurst or the Oracle type projects and if that number has grown since the prior call?

Marshall McCrea, Co-CEO

This is Mackie. Adam can provide additional details since he is closer to many of these developments. I want to commend our data center teams, one led by Adam and the other by Beth. We are actively pursuing every chance to supply gas or natural gas spot generation for data centers. Our pipeline positioning is strong. We're currently engaging with over 150 different opportunities, and it seems like we're seeing one or two new inquiries daily. We have already completed some deals that allow data centers to exercise options and utilize capacity with us. We're exploring a wide range of opportunities and negotiating actively. Our success so far has been impressive, and due to our talented team and robust assets, we anticipate significantly more deals related to electric generation supportive of data centers.

Adam Arthur, Executive

And this is Adam. I'll just add that in terms of project scope, they really vary in size, ranging from new long-haul pipelines to interconnects that are sitting right on top of our system, as Mackie mentioned earlier. We're at the intersection of transmission, fiber, and our assets, and are simply installing a new interconnect. So the scope really ranges from simple interconnects to larger pipeline projects.

Jason Gabelman, Analyst

Got it. Great. And my follow-up is more specific to the quarterly results. In the press release, there was a mention of this regulatory order impacting prior period and current period rates. So I wonder if you could provide a little more detail on what specifically that referred to and what that means for the increase in earnings moving forward? Because it seemed like there was a net benefit on the quarter and should provide a modest uplift of future earnings.

Adam Arthur, Executive

Sure. This is Adam again. I'll pass it over to Dylan to address the latter part of your question about future outlook. To begin with, we're very pleased with the appointment of Chairman Sweat and the steps that the FERC has taken under her leadership so far. Regarding the index issue specifically, in 2022, the FERC made a decision that was eventually found to be unlawful by altering the index methodology. Last year, the FERC issued an order that allows pipelines to recover those lost revenues. Those one-time adjustments reflect this situation, and Dylan can provide more insight into what the future looks like.

Dylan Bramhall, CFO

Yes, Jason. So why don't I just walk you through real quickly here or wrap up on the quarter and the one-time impact so we can kind of help you get a clean quarter to help how things are going to look going forward. On the NGL segment, we had $56 million from this regulatory order that was a one-time positive. Get a little carryover effect from where that sets the rates now, but that's primarily one-time there. We also had a negative $58 million on the timing of the hedge gains around our hedge NGL inventory, and a $14 million impact from the fog in Nederland. Both of those, that $72 million total we expect to recoup in the first quarter. So that's a big boost moving into 2026 there. That's a net negative 16 on NGL. Crude picked up 19 one-time from the regulatory order, and midstream lost 14 from transport fees that it pays on that regulatory order and also had about $20 million from producer shut-ins in the Permian where we saw some shut-in gas due to low, really negative pricing in Waha or negative 34 total net at midstream. And then the big one was a $60 million in transaction expenses. It's on related to closing of the Parkland transaction. If you put this all together, clean up the quarter, you've got a net negative about $90 million for that fourth quarter here that you'd want to add back to get a clean quarter. And like we said, you've got $70-plus million that we expect to recoup it that in the first quarter.

Operator, Operator

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

Thomas Long, Co-CEO

Once again, thank all of you for joining us today, but also a lot of appreciation for some very, very good questions, very good dialogue and discussion on this. As you can see, we've got a lot of great things to talk about with these projects. Not just for 2026, but for a long time into the future, like Mackie was mentioning. So I thank all of you. We look forward to all your follow-up questions, please get a hold of our IR team, and we're happy to jump on the call with you again. Thanks so much.

Operator, Operator

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