Energy Transfer - Earnings Call - Q3 2025

Executive Summary

• Mixed quarter: Q3 revenue of $19.95B and basic EPS of $0.28 missed S&P Global consensus ($21.81B revenue, $0.33 EPS), with EBITDA also below consensus; management cited several one-time items and segment-specific headwinds as contributors. Revenue/EPS consensus from S&P Global estimates: $21.81B*, $0.331*, EBITDA $3.97B* (company-reported Adjusted EBITDA was $3.84B).
• Guidance trimmed: 2025 Adjusted EBITDA now expected to be slightly below the low end of $16.1–$16.5B (lowered from prior stance) and 2025 growth capex reduced to ~$4.6B (from ~$5.0B); 2026 growth capex guided to ~$5B.
• Structural demand tailwinds: data-center and power demand accelerating—ET disclosed multiple long-term Oracle contracts (~900 MMcf/d), >6 Bcf/d of new demand-pull contracts with ~18-year average lives and >$25B of expected firm-transport revenue, and fully contracted 1.5 Bcf/d Desert Southwest pipeline with potential upsizing.
• Strategic optionality: considering converting one Permian NGL pipeline to natural gas service given tighter NGL transport economics vs superior gas transport returns; DAPL/ETCOP initiatives with Enbridge to bring Canadian heavy barrels bolster crude utilization into the 2030s.
• Distribution raised to $0.3325 per unit (annualized $1.33), up >3% YoY; liquidity strong with $3.44B revolver availability at 9/30/25.

What Went Well and What Went Wrong

• What Went Well

  • Record volumes across multiple assets: NGL transportation (+11%), NGL exports (+13%), NGL/refined products terminal volumes (+10%), midstream gathered volumes (+3%) YoY; strong interstate (+8%) and intrastate (+5%) gas transport.
  • Commercial momentum: fully contracted 1.5 Bcf/d Desert Southwest project (25-year terms), Oracle multi-site gas supply (~900 MMcf/d), >6 Bcf/d of new demand-pull capacity signed with >$25B revenue over ~18 years. “These contracts have a weighted average life of over 18 years and are expected to generate more than $25 billion of revenue from firm transportation fees”.
  • NGL segment growth: Adj. EBITDA up YoY on higher throughput and terminal fees; LPG export capacity at Nederland ~95% contracted through decade-end; Flexport ramping and ethylene export-ready.

• What Went Wrong

  • Headline misses vs estimates: revenue $19.95B vs $21.81B*, EPS $0.28 vs $0.33*, EBITDA (S&P definition) $3.59B vs $3.97B*; management cited several one-time items, including Rover ad valorem tax accrual ($43M) and NGL remediation costs ($17M).
  • Intrastate EBITDA down on lower optimization as business shifts to long-term third‑party contracts; Midstream YoY comp impacted by $70M prior-year business interruption proceeds; Crude pressured by lower Bakken/Bayou Bridge revenue and higher OpEx.
  • Guidance tightened: 2025 Adjusted EBITDA now “slightly below” the low end of $16.1–$16.5B range; 2025 growth capex reduced to ~$4.6B (timing deferrals).

Transcript

Speaker 1

Good day and welcome to the Energy Transfer Q3 2025 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on a touchstone phone. 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.

Speaker 0

Thank you, Operator. Good afternoon, everyone, and welcome to the Energy Transfer third quarter 2025 earnings call. Also joined today by Mackie McCrea and several other members of our senior management team who are here to help answer your questions after we get through the prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon. As a reminder, our earnings release contains a thorough MD&A that goes through the segment results in detail, and we encourage everyone to look at the release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10Q for the quarter ended September 30, 2025, which we expect to file tomorrow, Thursday, November the 6th. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Let's start off today with the financial results for the third quarter of 2025. We generated adjusted EBITDA of $3.84 billion, compared to $3.96 billion for the third quarter of last year. Excluding several non-recurring items, adjusted EBITDA was flat year over year. We saw several volume records during the quarter, including midstream gathering, NGL transportation, NGL and refined products terminal volumes, and NGL export volumes.

We also saw strong volumes through our natural gas interstate and intrastate pipelines. Year to date, we generated adjusted EBITDA of $11.8 billion compared to $11.6 billion for the same period in 2024. DCF attributable to the partners of Energy Transfer as adjusted was approximately $1.9 billion. For the first nine months of 2025, we spent approximately $3.1 billion on organic growth capital, primarily in the NGL and refined products, midstream, and intrastate segments, excluding Sunoco and USA Compression CapEx. Now turning to the results by segment for the third quarter, we will start off with the NGL and refined products. Adjusted EBITDA was $1.1 billion compared to $1 billion for the third quarter of last year. We saw higher throughput across our Gulf Coast and Mariner East pipeline operations as well as through our terminals. For midstream, adjusted EBITDA was $751 million.

Compared to $816 million for the third quarter of 2024. Results for the third quarter of 2024 included $70 million in proceeds from a one-time business interruption claim that was recognized in the third quarter of 2024. Absent this claim, midstream results would have been up compared to the third quarter of last year due to higher volumes in the Permian Basin, which were up 17% as a result of processing plant upgrades and new plants placed into service, as well as the addition of the WTG assets in July 2024. This growth was partially offset by lower gathering volumes in the dry gas areas. For the crude oil segment, adjusted EBITDA was $746 million compared to $768 million for the third quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems, including the Permian Joint Venture with Sunoco.

These were offset by lower transportation revenues, primarily on the Bakken Pipeline, as well as on Bayou Bridge, where we saw greater impacts related to some refinery turnarounds in Louisiana, which have since been completed and volumes have returned to normal levels. In our interstate natural gas segment, adjusted EBITDA was $431 million compared to $460 million for the third quarter of 2024. Results for the quarter included a $43 million increase related to the resolution of a prior period ad valorem tax obligation on our Rover System. Excluding this accrual, interstate results would have been up compared to the third quarter of last year due to higher demand on several of our interstate pipeline systems. For our intrastate natural gas segment, adjusted EBITDA was $230 million compared to $329 million in the third quarter of last year.

During the quarter, we saw increased volumes across our Texas intrastate pipeline system due to third-party volume growth. This was offset by reduced pipeline optimization, primarily as a result of our continued shift to more long-term third-party contracts, which are expected to provide more stable revenues at good rates over the next 10-plus years. Now, looking at the organic growth capital guidance, we now expect to expend approximately $4.6 billion on organic growth capital projects in 2025, compared to our previous guidance of $5 billion. This is a result of project forecast reductions as well as spending deferrals into 2026. Looking ahead to 2026, we expect growth capital to be approximately $5 billion, the majority of which will be invested in our natural gas segments. We continue to expect our growth project backlog to generate mid-teen returns.

The majority of the earnings growth associated with the Flexport Permian Processing, NGL Transport, and Hugh Brinson Pipeline Expansion Project is expected in 2026 and 2027, promoting strong growth in the coming years. Beyond these projects, we also have a significant backlog of opportunities which support continued growth. Taking a closer look at some of our recently approved and currently underway projects, we continue to see significant demand for our services on the natural gas side of our business, which is expected to support growing demand for gas-fired power plants, data centers, and industrial and manufacturing. First, looking at our Desert Southwest Pipeline project, which we announced last quarter, this strategic expansion of our Transwestern Pipeline will enhance system reliability and provide new and existing markets in Arizona and New Mexico with access to low-cost, reliable Permian Basin natural gas.

We recently completed an open season, and the 1.5 Bcf per day project is now fully contracted under long-term commitments with investment-grade counterparties with a term of 25 years. This includes a $400,000 MMBtu per day contract with a new demand source along the pipeline route. In addition, since the launch of the open season, we have received significantly more interest in current planned capacity, and we are evaluating options around a potential increase in capacity. We also recently entered into commitments with US Pipe Mills to lock in the majority of space and delivery for pipe in the fourth quarter of 2027 at favorable prices, and we expect to have 100% locked up very soon. Since the day we announced this project, our teams have been actively engaging with elected officials, county leadership, and associated communities along the route to communicate project information and updates.

To date, we have engaged with over 175 stakeholders who have interest in or are involved in this project. Our discussions have been very positive, as these stakeholders are pleased about the economic benefits expected and also realize the critical need for a substantial supply of gas to help address the significant demand growth in Arizona and New Mexico markets by providing access to reliable, affordable electricity. Next, we continue to expect phase one of our Hugh Brinson Pipeline to be placed into service no later than the fourth quarter of 2026. As of today, 100% of the right-of-way has been acquired for the proposed route. Over 85% of the pipe has been delivered to our pipe yards, and construction is underway on all five spreads of phase one of the project. In addition, last quarter, we announced phase two of the project, which will include additional compression.

This system will be bi-directional, with the ability to transport approximately 2.2 Bcf per day from west to east and approximately 1 Bcf per day from east to west. The Hugh Brinson pipeline will provide significant optionality by connecting shippers to our vast natural gas pipeline network, as well as providing access to the majority of gas utilities in Texas and to every major trading hub in Texas. Additionally, our existing customers have the option to increase their volume commitments, and we will expand the system to meet those commitments in accordance with those agreements if exercised. At this point, over 90% of our 3.8 million MMBtu per day of Texas crosshaul capacity is sold out with demand charges through 2036, with the majority of this volume extending out through the remainder of that decade. This includes Hugh Brinson.

All the other pipeline flows from the Permian Basin to markets in the east. We have also sold capacity from east to west on these same systems, which will add significant revenue to our pipeline assets without additional capital. We are constantly evaluating whether our pipelines can generate more revenue by transporting a different product. In numerous instances, we have converted systems to different products, which have generated significantly more revenue once they are converted. Although we are highly confident that we can keep our NGL pipelines out of the Permian Basin at or near capacity, we are considering converting one of our NGL pipelines to natural gas service.

Considering the contracts we have already consummated, as well as the numerous transactions we are negotiating, we believe we may have the opportunities to significantly increase the value of that capacity by converting it from natural gas liquids to natural gas transportation service. In August, we also approved the construction of a new storage cavern at our Bethel natural gas storage facility, which is expected to double our working gas storage capacity at the facility to over 12 Bcf, and we expect to place the new cavern in service in late 2028. This expansion will increase our equity gas storage capabilities to serve growing demand in the heart of our extensive intrastate natural gas pipeline network and will further strengthen the reliability of our systems, as well as provide the opportunity to benefit from pricing volatility.

We are well positioned to meet the future growth, and we have the ability to develop at least 15 Bcf of additional storage capacity at Bethel. Now, for a brief update around the recent natural gas opportunities for new power plant and data center development, as a reminder, on our last call, we announced that we had signed a deal to provide natural gas supply to a major hyperscaler in Texas. Since then, we have added to that agreement and are now able to disclose that we have entered into multiple agreements with Oracle to supply natural gas to three US data centers, two of which are in Texas. Under the terms of these long-term agreements, Energy Transfer will deliver approximately 900,000 Mcf per day of natural gas.

Supply for these agreements is expected to be sourced from our extensive intrastate pipeline network, and construction of a new pipeline lateral from Hugh Brinson and our North Texas pipeline is underway. First flow is expected to occur by the end of the year, with final completion to follow in mid-2026. We have also entered into a 10-year agreement with Fermi America to provide a pipeline interconnection and exclusively provide initial gas supply of approximately 300,000 MMBtu per day to Fermi's Hypergrid campus located outside of Amarillo, Texas, subject to Fermi's election. Energy Transfer has entered into several of these types of exclusivity agreements with data center and power plant customers, reflecting more than 1 Bcf of additional supply should these projects move forward.

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

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

Now, looking at the Permian processing expansions, as a reminder, both the Lenora 2 and Badger 200 million cubic foot per day processing plants are in service. The Lenora 2 plant is currently running at full capacity, and the Badger plant continues to ramp up. As a result of our recent processing plant optimization and expansion projects, our process volumes in the Permian Basin, as well as Y grade transportation throughput from the Permian, reached new records during the quarter. In addition, we continue to expect our Mustang Draw plant to be in service in the second quarter of 2026. We also recently approved the construction of Mustang Draw 2, which will have a capacity of 250 million cubic foot per day and is supported by continued growth from existing customers.

Mustang Draw 2 is expected to be in service in the fourth quarter of 2026 and is expected to cost approximately $260 million, including spend related to additional gathering and downstream pipeline infrastructure. It will add additional revenue to our downstream assets as well. At our Nederland terminal, our Flexport NGL export expansion project was previously placed into ethane and propane service, and volumes are expected to continue to ramp up throughout the remainder of 2025. In addition, the facility is now ready for ethylene export service. We expect to have over 95% of all LPG export capacity at Nederland contracted through the end of this decade. In our crude segment, an expansion is underway at our Price River terminal in Wellington, Utah.

This expansion, which is backed by an agreement with Four Point Resources, is expected to double the terminal's export capacity and enhance its deliverability of American Premium Uinta Oil to markets throughout the lower 48. The expansion includes new railcar loading facilities, a new heated storage tank with approximately 120,000 barrels of capacity, and two additional 6,000-foot storage unit tracks, which will significantly improve storage capacity at the facility. The project is expected to cost approximately $75 million. It is expected to be in service in the fourth quarter of 2026. In September, Energy Transfer, along with Enbridge, completed a successful open season for the Southern Illinois Connector project, which resulted in 100,000 barrels per day of contracts for transportation of Canadian crude oil to Nederland from both Flanagan and Hardesty.

This project will connect Enbridge's pipeline near Wood River to Energy Transfer's assets in Patoka, Illinois, to support the delivery of Canadian crude oil to U.S. refineries, further strengthening market connectivity and value for all our stakeholders. Separately, Energy Transfer is working with Enbridge to provide capacity for approximately 250,000 barrels per day of Canadian crude oil through our Dakota Access Pipeline. This project would provide much-needed capacity for oil out of Canada and would be a significant part of the steady volume throughput on Dakota Access for many years to come. We have taken FID on the Southern Illinois Connector project and expect to take FID on the other project by mid-2026. We are very excited about both projects, which would fill available and additional capacity on our Dakota Access and ETCOP pipelines, and we look forward to providing additional details in the future.

Turning to Lake Charles LNG, we're in advanced discussions with Mid Ocean Energy related to its participation as a 30% equity owner of Lake Charles LNG with a commissary percentage of LNG offtake. We're in discussions with other parties for the remaining equity we intend to sell in order to reduce Energy Transfer's equity interest to 20%. We are also in the process of converting non-binding heads of agreement with several offtake customers to binding agreements for the remaining volume of offtake needed for positive FID. FID on the project will be dependent upon bringing these items to the finish line. We continue to be extremely focused on capital discipline. The process we are going through during the development of our LNG project highlights this focus. Our projects need to meet certain risk return criteria, and we are not there yet on LNG.

Now, turning to guidance, we expect to be slightly below the lower end of a guidance range of $16.1 billion-$16.5 billion. Looking ahead, Energy Transfer is one of the best-positioned companies in the industry to help meet the substantial growth in demand for energy sources over the next several years. We are leveraging our strong relationships to develop new projects backed by high-quality counterparties on both the supply and demand side, and we see growth opportunities across all aspects of our business. When combined with our existing natural gas pipeline network, our Hugh Brinson, Desert Southwest, and Bethel storage projects further establish us as the premier option for customers seeking reliable natural gas solutions to support their power plant and data center growth plans. Our significant processing capacity expansion in the Permian Basin will help feed our downstream pipeline network.

We are continuing to expand our NGL business in the United States to help meet growing international demand, and we continue to expand our crude oil pipeline network with strategic projects that will help fill available and additional capacity on our existing pipelines. In short, we have an extensive backlog of growth projects that are coming online over the next several years, and we continue to be extremely focused on capital discipline. These projects are highly contracted under long-term agreements, many of which are demand pull in nature, and they are expected to generate significant revenue, providing strong returns and considerable earnings growth over the next decade or more. That concludes our prepared remarks. Operator, let's open the 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 telephone keypad.

If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Keith Stanley with Wolfe Research. Please go ahead. Hi, good afternoon. First, just wanted to clarify on the guidance for the year. So saying you'll be a little bit below the low end of the range for 2025, does that include Sun's acquisition of Parkland, or is that still stripped out when you're making that statement? Hi, this is Dylan. For the guidance statement, we have not included Parkland in there. So we're saying without Parkland, we expect to be slightly below the initial guide. Okay, great. And then picking up on Lake Charles, where you left off there, can you give us more detail on, I guess.

Realizing you guys are showing capital discipline, just how many more contracts you need at this point to firm up. I guess where you are timing-wise in the sell-down process. To get to an FID decision? Yeah, Keith, this is Mackie. Let me step back real quick. We worked on Lake Charles for a lot of years. We've had different partners. We've gone through the pandemic. We've gone through DOE positive, LNG positive, Ukraine, everything kind of ebbs and flows. Tom and Amy and his team have done a great job of getting markets in difficult times, especially when we're competing against companies that that's all they do is LNG, and they're willing to go to FID without having sufficient contracts to provide, excuse me, guaranteed rates of return.

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

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

We're hoping that these equity partners will step up by the end of the year and get us to where we want on kind of the risk profile and the participation we want in this project. We're going to keep our heads down. We'll see over the next couple of months how things turn out. We're pushing hard to get there, but we've got a ways to go. Very helpful. Thank you. The next question comes from Jeremy Tonet with JPMorgan. Please go ahead. Hey, this is Elion for Jeremy. Just wanted to start on some of the recent data center deals you guys have signed. Just trying to get a sense of the financial impact going forward. Just given the size of the partnership, understand the orders of magnitude that it could have to the business. If you can provide some commentary there. You bet.

I think probably seven or eight of us would love to talk about this. It's so exciting. We talk about it every time we get on these calls. A year ago when we announced Hugh Brinson, we didn't even know what a data center was. We kicked it off a little less than 1.5 Bcf, and then data centers kicked in, and it's really been an impetus between that pipeline. Also, Desert Southwest had a lot to do with data centers, and it just opened up the door for so many opportunities we're so excited about. The unique nature of these data centers, especially the hyperscalers, they're very confidential. So unlike a lot of our business, we can't really talk about it. IR can't really get out there and get out in front of it.

We were pleased to have the ability to disclose what we disclosed for this earnings call. Believe me, and Tom said in the opening statements, we have so many of these we're chasing. A lot of them are high probability to get there. As far as how many we've done so far than what we've disclosed, which is on demand pull, a lot of that. $25 billion is toward data centers. I'll say one more thing too around data centers. Besides the fact that so many of them are in such close proximity to our pipelines, the Hugh Brinson pipeline, I believe, and I even think I've said this to a lot of our folks here, is that I think it'll be the most profitable asset we've ever built.

The reason for that is it's kind of the main artery connecting the Permian Basin with the rest of the world, the Southeast, East, and the rest of Texas, Gulf Coast, and all that. Not only have we sold out to this 0.2, we have data centers that have options over the next few quarters to exercise the right to create 800,000 more capacity. We'll be doing some more looping of Hugh Brinson. In addition to that, we've sold a material amount of capacity, significant revenues from an east to west standpoint, which means a backhaul with no additional capital. I think our data Adam's sitting here with me. He leads our data center group in Texas, and we couldn't be more upbeat about where we sit today through data centers throughout the country, but especially in Texas because of our ability to.

Perform and provide reliable gas to all these data centers, and because of our close proximity to where these are being built and our ability to source from Waha, Maypearl, Katy, Heck, South Texas, Carthage, you can even leave the state and bring gas into some of these data centers. It is something we will be able to talk more and more about as these confidentiality issues go away, as we are able to visit more. We are very excited about the future, and it is hard to over-exaggerate what these data centers and power plants associated with those, and power plants unassociated with those, for grid, to deliver electricity into the grid. A very positive, exciting part of our growth for many years to come. Thanks.

Recognize 2026 budgeting is likely ongoing, but just want to think about at a higher level the kind of major puts and takes that you guys are looking at, both on the base business and then some of the organic growth projects that you're bringing on. Just kind of framing the high-level drivers for performance next year. Yeah, this is Dylan. As we look at next year, I think the biggest piece is really to look at our, we are going to have really the main impact of Flexport coming online. Those contracts kick in basically January 1. While we've got a little bit of spot volumes running here through the third and fourth quarter this year, we're going to get the full impact of Flexport coming online. Permian plants continue to fill up plants.

We've got new plants that we're constructing right now, so we'll see the continued growth out of that. With all those plants, remember, we're sending those liquids down our NGL lines into our NGL and fractionators as well. That will continue to be growth. We'll have Frack 9 coming on next year as well. Those are the main pieces there. Hugh Brinson will come online at the end of the year next year. We'll just wait to see, based on timing, how much impact that'll have as well. Great. I'll leave it there. Thanks. The next question comes from the line of Teresa Chen with Barclays. Please go ahead. Good afternoon. I want to ask about the consideration of converting one of your NGL pipes to natural gas service in the Permian.

Would you be able to provide any additional details related to that at this point? Which pipeline do you have in mind for this? I imagine something directed to the Gulf Coast. What would be the cost and related economics of doing something like this? Yeah, this is Mackie again. Let me give a quick little history. You will probably know most on the call that we are constantly looking at every one of our assets. If assets are underutilized and could be put into a different service, we do that. We have a record of doing that. Dakota Access would not have been a project without our ability to convert our 30-inch trunk line from natural gas to oil. It was very beneficial to the North Dakota producers to get a good rate down to the Gulf Coast.

We converted a TW line that's a natural gas interstate pipeline to natural gas liquids, which has been instrumental about getting a lot of liquids out of the Delaware Basin into our pipeline network. Also, our JC Nolan, it was a liquid line that we converted to diesel and are flowing diesel from the refineries in the Gulf Coast to West Texas. It is something we're constantly looking at. What we've run into on the NGL front is that we have some tiers, some contracts, cliffs, over the end of this decade that are kind of approaching. As we negotiate to extend and/or fill that up, what we've started to recognize is there's been a lot of announcements. One of our competitors several months ago announced a large amount of NGL line. There was just the most recent pipeline announcement for an NGL line.

We're scratching our head at how in the heck in this environment, at the rates these folks are quoting to producers, how they can build these assets and get any kind of reasonable rate of return. What it's causing us to look at is, we have three NGL pipelines out of the Permian Basin. Does it make sense to continue those NGL service? It may. We're in negotiations with over 300,000 barrels right now. We're looking at it very closely as we continue to negotiate. As the fees get more and more tight and more competitive, it just doesn't make sense. You correlate that with the success Adam and his team have had on these data centers, and you start putting numbers to it. If these options are exercised over the next few quarters, we're going to be looping pipe.

We're going to have to be required to loop Hugh Brinson, make it a bigger project. We could forego between $800 million and $1 billion. If you look at the rates that we'll have to move that gas on the anticipated volumes that we'll recontract up at these much reduced rates, some of the scenarios show twice the revenue with natural gas as what we might see with NGL. This is not something we're making a decision on today, but as we always look at and analyze, how do we make the most money we possibly can for our unit holders with the assets we have? We are certainly seriously looking at this conversion. Understood.

On that same line of thinking as it relates to capital efficiency, your agreements with Enbridge on the crude side and moving WCS through DAPL and ETCOP to Nederland, it seems like that timeline would line up nicely with DAPL's recontracting in the 2027 timeframe. Considering the narrowing of Bakken differentials over time, certainly a new source of barrels is welcome. From an earnings perspective, are these connections backfilling volumes and maintaining earnings at the level that they are versus facing a contract roll-off, or would you expect earnings growth across your crude assets as these projects come online? This is Mackie again. I think we probably use the word exciting, excitement too much, but we're very excited about what's going on up there and teaming up with Enbridge. Because you're right, it's almost like you've got somebody in our office. You're right.

I mean, we've seen volumes level off. If you talk to the majority of the largest producers in the Bakken, they're not talking growth anymore. They're talking kind of flatline. As these cliffs fall off of some of these contracts, the timing with what we're doing with Enbridge could not be better. We just announced today that we've got an FID on 100,000 barrels of heavy that we'll deliver into our southern end of our Dakota Access, which we call ETCOP. What's even more exciting is the need for Canadian barrels to find better markets. The best markets for Canadian barrels are U.S. refineries. We are very pleased with where we sit with Enbridge. They are going through a process with the Canadian producers. It's going to take several months. I'm not sure I've heard or we've heard any protests, exceptions, or anything. Everybody's fully behind this.

We kind of think of this as the first phase. That's 250,000 a day. To answer your question, it fits in perfectly. Our first priority would be to make sure that we give the opportunity for all the producers in North Dakota to sign up for whatever term they want to make sure there's capacity on Dakota Access for their pipelines. That's our first priority. Our second one is keeping our pipeline full. We have the ability to move 750,000 barrels a day. We're 500, 550 today, so we can move a lot of the barrels from Enbridge without much capital. We also think this may be just a stepping stone of what we may be able to accomplish with Enbridge out of North Dakota.

Anyway, on the first 250, that will parlay in very well with any declines or any cliffs that we have on existing with the timing of these first 250,000. Then, like I said, we think there's also some upside. As Tom said in his remarks earlier, we are so excited about the timing of this and how it's going to keep Dakota Access full for a long time because these are 15-year agreements that we'll be working on with the Canadian producers. It'll take us into the 2020s. Sorry. Thank you for the detailed answers, Mackie. The next question comes from the line of Spire Dunas with Citi. Please go ahead. Hey, Separator. Afternoon, guys. I want to start with the growth backlog more broadly.

I'm curious how you're thinking about the total opportunity set for growth, maybe beyond the sanction projects and a lot of the ones you've talked about today. Some of your peers have started to quantify these opportunities with multi-billion dollar backlogs. Curious if that's a number you'd be sort of willing to share, or maybe even another way to think about it, how do you think about a new run rate for CapEx in this environment? Yeah. Listen, I'll go ahead and start off with that. This is Tom. We have put out the $5 billion for next year. Obviously, as we get into early next year and year-end, we'll keep that number updated for you. You can see we do have a great backlog of very good high-returning projects.

If you start trying to look out further than that, I do not know that we can really give you a lot of guidance there, but you can see just from what we are already talking about. I am not trying to guide you toward the 26 number continuous, but you can see we continue to have a lot of opportunities. We have got a great team that is out there chasing a lot of these. In fairness, at this stage, do not really have probably a number for you there, but it is going to be a strong number. There are going to be good returning projects, and we are going to make sure that we have the appropriate risk on them too as we venture off into these. Got it. No, Tom, I appreciate taking a swing at that one. Second one, maybe just going to Desert Southwest.

You mentioned seeing additional interest there. Could you maybe just remind us again how you're thinking about upsizing that pipeline, what diameter you're looking at now? And you also mentioned, I think it was 400,000 dekatherms a day of demand source along the route. Could you just expand a little bit more on that? Yeah, this is Mackie again. Yeah, Beth and her team did a fantastic job. We kind of, in a lot of these cases on these projects, started way behind. It took a while to get there, but we were very pleased to announce that. We've been just, we've taken trips to Washington. We've been to both states along the way. The project is very highly thought of from a political standpoint and from an economic standpoint. Huge upside there. We did complete the open season, as we have said.

There's at least a Bcf above what we've already sold out, above the 1.5 Bcf. We're in a lot of work to figure out some of those involved, some laterals off of DSW. We've got some work to do. We certainly have the capability of increasing it by at least half a Bcf, possibly up to a Bcf. We'll be making those decisions over the next five or six weeks. We've locked in steel prices for the majority of that project. Up until the middle of December, we have the flexibility to go from a 42 to a 48 or any combination thereof. We sit in a really good spot where we've already locked in prices. We'll see how it plays out. As far as the 400,000, that kind of falls under that unique nature of confidentiality.

We can't say a whole lot more on that. That project and others similar to that, we are chasing. I would say we're pretty confident that we will expand it higher than 1.5 Bcf, but not sure if we'll get to 2.5, but we'll see how the next six weeks play out before we have to make a decision on pipe size. Got it. I'll leave it there. Thanks, Mackie. The next question comes from Giannon with Bank of America. Please go ahead. Hi. Good afternoon. Congrats on all the data center deals. I know you get asked this frequently, but you've been so active with the hyperscalers. I think you said earlier this year that Energy Transfer's place in this story is primarily gas supply. What keeps you from wanting to go into the power generation itself in a bigger way? This is Mackie again.

I think we're all anxious to answer this. Because we like good rates of return on our projects. Unless we've missed the boat on that, the opportunities that we've seen are low double, if not high single digit. It just doesn't fit. I mean, we'd love to team up with the folks that are generating those projects and provide all the gas they want. Not saying that we never will participate in that, but we'd have to see a lot better rate of returns than what we've seen in the projects we're aware of. That's very clear. Thanks. As a follow-up, earlier this year, you FID'd the Bethel gas storage expansion. Are gas storage rates high enough today to drive material other brownfield storage expansions in the U.S., or is Bethel kind of a unique case?

Do you kind of see more upside on gas storage rates as LNG starts up in the next few years? What ending do you feel like we're in and those rising? Yeah, I go again. Here we go again. Exciting. Storage is another huge area for us. We have about 233 Bcf of storage. We're expanding Bethel by another 6 Bcf, which is about 240 Bcf. The majority of that, probably 190 Bcf, is in Oklahoma, Louisiana, and Texas. Very well positioned, tied to our large downward pipeline. With the absolute necessity of reliable gas supplies to all these data centers, it's imperative that we have the ability through our big inch downward pipes to deliver, and more importantly, to deliver when we have freeze-offs in Oklahoma or freeze-offs in the Permian Basin or other areas. We believe that the value of storage is going to skyrocket.

You think about 30 Bcf of LNG that's going to come online by the end of this decade, early 2030, and you pick a Harvey, you pick a hurricane that spins along the Gulf Coast for days. Yes, there's some storage capability of all these LNG facilities, but there's going to be problems. It's going to happen. We're going to be very well positioned. As far as Bethel, which we had 100 Bcf there, it's in the heart of all of our large diameter systems. It gives us the ability to come out of those systems and go to anywhere in Texas, all the major hubs, all the major utilities, as well as going into the interstate markets, both at Waha area, Iron Interstate, and others, and also the Carthage area. We're very bullish.

However, we're not going to go out and just spec a bunch of storage. We're very disciplined. It's kind of where we're at now in all of our capital spending, as Thomas said several times. It doesn't mean that within the next six months, we don't kick off another storage to back another project. It's very important to our data center customers. We have a lot, and we look forward to talking over the next few quarters of a lot of others that we intend to add. To not only have the capability we have, I just said, to come on all these other receipt points, but also in dire times like Erie and tough times, we have the ability to perform unlike anybody else in storage, gives us that backdrop to be able to do that. Very clear. Thank you.

The next question comes from Michael Blum with Wells Fargo. Please go ahead. Thanks. Why don't you go back to the data center. Deals you've announced, Energy, Permian, Oracle. Is there a way can you provide us any kind of framework for how to think about the capital outlay for each of these data center supply projects and your expected returns? I realize they're all a little bit different, but just high levels or a way to think about that. Sure. High level, and we've said this before, a lot of the data centers we're talking to, very low capital. As I mentioned earlier on Hugh Brinson, we didn't have a data center in our head when we announced that project. And then lo and behold, we go through right by Abilene, one of the largest, potentially largest data centers in Texas.

All we have to do is lay a lateral, a 24-inch lateral, kind of a loop system that provides what's going to be needed at that location. You look at Franklin Farms in North Louisiana, we're looking at less than 20 mi away. Pretty low capital stuff. Others, depending on where we go, there's a couple of them that are kind of out in the middle of a Panhandle that we look at laying to. Those would be capital exclusively for the large capital dollars, exclusively for those opportunities. Michael, I think you said it well. It's all across the board. I mean, it can be embedded in some of our large downward projects that we already have built. It could be embedded in projects that we've announced.

Part of that is data center expansions, which is what helped us expand Hugh Brinson, was these data center deals that we have done. It is kind of a combination. I would say a lot of what we are looking at now, especially in Oklahoma and other areas of Texas that we are very close to getting some deals done, is much less capital than for the amount of volume that we are talking about. I will add one more thing to that. We have some data centers that have secured their electricity supplies somewhere, renewables somewhere else. Yet, they are willing to pay large demand charges for the ability to instantaneously pull gas from our system in the event they have interruptions from there.

Those are very low capital projects that we'd be utilizing, as I mentioned earlier, our storage capabilities along with our large diameter capabilities to move large volumes quickly to these locations. Okay. Got it. Thanks. That makes sense. Just a clarification on your earlier comments on Lake Charles. I guess the first question is, do you see this as you're definitely going to get to FID, or is it really subject to all those criteria that you laid out earlier? If you do get to FID, what's your latest on when you think timing-wise you'll get there? Thanks. Yeah. Let me make this real clear. Yeah, we will not proceed with LNG until we have secured 80% of equity partners similar to ourselves. We've got some work to do to do that. I mean, getting the contracts done, feel great about that.

EPC contract, feel great about that. The last big, most important box, especially as we're emphasizing this financial discipline that's very important to us, when you're only chasing one or two projects, you don't think about it as much. When you're chasing billions of dollars in projects, several of which we've already announced, we've got to be careful in stepping out on something like this. We're not an LNG company like we're competing with. We're a pipeline company that has an LNG or a regas facility converting part of it to LNG. No, we're not going to get to FID until we have the required amount of equity partners that we need.

As we said, we've got our work cut out for us to get that done timely enough to be able to get to FID in relation to our EPC costs that we have with our EPC contractor today. Thanks. The next question comes from Zach Guan with TPH. Please go ahead. Hi. Thanks for taking my questions. Maybe going back to Hugh Brinson. Now that phase one's fully contracted and we've seen a few producers come out and indicate they signed up for capacity, can you talk to the breakout of supply push from Waha and demand pull contracts from data centers and other demand sources on that pipe? Yeah. This is Mackie again. I think you said Hugh Brinson. It seems like we didn't hear the first part of that. But yes. That project started out as demand pull.

To kind of get it to the finish line, we had a lot of producer push. And now, as we've grown and expanding it, it's pretty much all demand pull. It has been a pretty balanced combination of those two. What we do see on the growth on any type of expansion will be a demand pull. Okay. Perfect. I know this might not be your arena and more on the end customers, but it feels like there's a lot of straws going into the Permian for gas between your projects and various other ones through the end of the decade. Have you seen your customers start to talk about actually signing supply deals out of Waha to make sure the gas is there on top of the FT contracts they have with you all? What a great question.

It's interesting because if you don't think we're looking at this closely and doing our own studies in this, but there's been four pipelines announced. Depending on rumors about one of those going to a 48-inch, possibly one of ours going to 48-inch, you could see north of 11 or 12 Bcf of new demand projects built out of that, not counting probably a half a Bcf to a Bcf of data centers that are built in the Permian Basin. To answer your question, we are aware some of the end users have reached out to producers to try to lock some of that up. The great thing about our assets, our gathering assets, our intrastate, our interstate assets going out of the Permian Basin, it can do nothing but grow dramatically. It's got to grow between 12% and 15%.

Just to get enough gas to fill the pipes that have been already announced over the next four and a half years. If I was the market, I would be out locking up production today. Perfect. I appreciate all the color there and thanks for the time. The next question comes from John Mackay with Goldman Sachs. Please go ahead. Hey, guys. Appreciate the time. Quick one for me. You have in this slide on gas going to the power. You talk about six Bs of new deals signed over the past year. If you do some math, it's actually a pretty good margin on those. I'd love to know how much of that six is kind of incremental growth on top of kind of what the business is doing right now.

Yeah, if we were to kind of back into a margin on what that or a fee and what that's implying, is that a reasonable run rate for what you guys are seeing on some of these incremental power data center deals? Yeah, John, this is Dylan here again. Yeah, that's all incremental business that we've signed up that we're not currently doing today. These are all new demand sources that are in the process of being constructed right now, and that's all incremental. Now, backing into the fee, yeah, that's correct. If you do that math, you will back into a fee. That is made up of a lot of different types of contracts, so I'd be careful on trying to just project that forward on everything. I mean, that's got a good mix of.

Desert Southwest, some of the stuff off Hugh Brinson, and then a couple of Bcf of just other demand growth along our systems where we're building laterals out too. When you put that all together, yes, you do get to that pretty strong weighted average fee. Like I said, it is made up of those different sources. All right. That's absolutely clear. Thanks for the time. Thank you. This will be our last question. It's from the line of Manav Gupta with UBS. Please go ahead. Thank you for squeezing me in. I'll ask only one question. Bloomberg has reported that Energy Secretary Wright has sent a draft proposal to FERC that would limit the regulator's review period for data center connections to power grid to 60 days, expediting the process, which can currently take years.

I'm just trying to understand if this proposal does go through, could that mean a material acceleration in demand for natural gas to support electricity generation? Because honestly, it's like bring your own electricity right now. You might be the only game or your pipelines might be the only game in town if this proposal actually does go through. Yeah. I mean, I think we had not heard that yet, but that would definitely be a big boost to the pipeline business. Being able to move that quickly there would definitely be great for our business. Okay. Can you elaborate a little bit on the expansion of Price River Terminal? Looks like a very interesting project, an exciting project. What would be the demand for this expansion? Yes. Once again, Adam's sitting there next to me. What a great project.

Years ago, we kind of took over that, and it was kind of struggling. Our team worked very hard to really grow that business. It is phenomenal what they have done. I would say we have got—I do not even know what % locked in of the acreage up there—but it is a significant amount of that acreage that is locked into us for many years to come. For a lot of refineries, that is very valuable, kind of waxy oil that fits what they are looking for. Not only is that a great project for us as we expand that terminal, we also see a lot of synergistic downstream revenue possibilities with a lot of those barrels going to St. James and possibly to Nederland. There is a lot of upside even to that project. Standalone, that is going to be a really great project for us. Thank you so much. Thank you.

This concludes our question and answer session. I would like to turn the conference back over to Tom Long for any closing remarks. Alison, once again, we do thank all of y'all. As Mackie answered on several of the questions. Excited was the most commonly used word here of how excited we are. And you know that we've always dreamed of kind of getting to this point right now through our growth here with M&A and organic growth projects. The reason why you're seeing a lot of this is just because of the massive infrastructure that we've built up and where our assets sit. That's what's provided the opportunity. We are going to stay very disciplined on our capital. These are the kind of projects that are just very high-returning projects that are right in our wheelhouse.

We are going to continue to chase them with a great commercial team and the ENC team to build them. Of course, the finance team and the rest of the group, the team to be able to keep everything going. You are going to see these opportunities. We look forward to talking to you more about this capital and about these great projects. Appreciate all of you joining today. We look forward to the follow-up questions. Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.