Enterprise Products Partners L.P. (NYSE:EPD) Q3 2025 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q3 2025 Earnings Call Transcript October 30, 2025

Enterprise Products Partners L.P. misses on earnings expectations. Reported EPS is $0.61 EPS, expectations were $0.651.

Operator: Thank you for standing by, and welcome to Enterprise Products Partners L.P.’s Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

Libby Strait: Good morning, and welcome to the Enterprise Products Partners conference call to discuss third quarter 2025 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s General Partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I’ll turn it over to Jim.

A. Teague: Thank you, Libby. Good morning. Before we dive into our third quarter results, I want to take a moment to recognize the upcoming retirement of Tony Chovanec. Tony has been more than a colleague. He’s been a dear friend and a guiding force at Enterprise for nearly 2 decades. His leadership in building our Fundamentals and Supply Appraisal team helped steer Enterprise through the shale revolution and set the standard across the industry. We wish him all the best in the next chapter and thank him for his invaluable contributions. Tony will be with us through the start of next year, but we wanted to make sure we had an opportunity to congratulate him on an incredible career on this call.

Tony Chovanec: Jim, I really appreciate those kind words and all you all here around the table. I really appreciate you all. People on the call, the analyst community, our producers, our customers around the world. I’m forever grateful for the interest and respect that you’ve always shown for in our fundamentals and our supply appraisal work sincerely. Jim, I want to thank you for years ago when we sat down at your table, recognizing early on that we had something that we now know is the shale revolution. And as you put it, you had a bunch of reports on the table in front of you, and you told me something is different this time and given me the chance to establish a Fundamentals team that I’ve been so honored and frankly, humbled to be part of, and I really mean that. I guess last but not least, Corey Johnson, the Data Science team that what you all have taught me over the last 4 years, I’ll take with me the rest of my life. So thanks to everyone. Thank you, sir.

A. Teague: Yes, I’m about to crack, Tony. Now the results. Today, we reported adjusted EBITDA of $2.4 billion for the third quarter, generating $1.8 billion of distributable cash flow, providing 1.5x coverage. Additionally, we retained $635 million of DCF. When I look at the third quarter results, I’m reminded of the long anticipated projects we’re commissioning in the fourth quarter. Third quarter results were lighter than expected, but far from discouraging as we look ahead to year-end and into 2026. After a 3-month delay, Frac 14 is now in service and will contribute to our results going forward. The Bahia pipeline and Seminole pipeline conversion will come online in tandem, adding capacity to our NGL pipeline system and returning capacity and flexibility to our crude oil pipelines.

We originally planned for these projects to be completed around midyear, but we look forward to completing them in the remaining months of 2025 and what they’ll deliver. Our PDH plants are looking up with PDH 1 averaging 95% of nameplate, and PDH 2 showing similar promise as it resumes operations following a third quarter turnaround to address coking in the fourth reactor, an issue the technology licensor order has committed at the highest levels to resolve. If you add all that up, I see a lot of upside that was pushed out of the third quarter. As you know, our petrochemical facilities at Mont Belvieu have faced their share of opportunities and challenges. Enterprise is built on engineering and operational excellence, and Randy and I couldn’t be more proud of the incredible work our petrochemicals teams have done to bring these assets up to our standard.

We’ve never been more confident in the team we have in place today. With the Neches River terminal set to be completed next year, we’re nearing the end of a multiyear, multibillion-dollar capital deployment cycle that began in 2022. These strategic investments, including pipelines, marine terminals and key acquisitions puts us in a great position to capitalize on long-term growth from the Haynesville and Permian Basins. Finally, I’m sure Randy is going to hit this, but I kind of enjoy stealing his thunder from time to time, to say this morning, we announced a $3 billion increase to our buyback program, taking it from $2 billion to $5 billion. While we see plenty of opportunities to efficiently expand our footprint in the future, we are also well positioned to continue our strong track record of returning capital to our unitholders.

Growing distributions will continue to be our primary focus, but this expanded program enhances our flexibility to grow buybacks alongside rising free cash flow. We’re excited about the next chapter, not just in the years ahead, but in the decades to come. And with that, I’ll turn it over to Randy.

W. Fowler: Thank you, Jim, and good morning, everyone. Starting off with the income statement. Net income attributable to common unitholders was $1.3 billion or $0.61 per common unit on a fully diluted basis for the third quarter of 2025. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital was $2.1 billion for the third quarter of 2025. We declared a distribution of $0.545 per common unit for the third quarter of 2025, which is a 3.8% increase over the distribution declared for the third quarter of 2024. The distribution will be paid November 14 to common unitholders of record as of the close of business, October 31. In the third quarter, the partnership purchased approximately 2.5 million common units under its buyback program for $80 million.

Total repurchases for the first 9 months of 2025 were $250 million or approximately 8 million enterprise common units, bringing total purchases under our buyback program to approximately $1.4 billion. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 3.5 million common units on the open market for $114 million during the first 9 months of 2025, including 1.2 million common units on the open market for $37 million in the third quarter. For the 12 months ending September 30, 2025, Enterprise paid out approximately $4.7 billion in distributions to limited partners. Combined with the $313 million of common unit repurchases over the same period, Enterprise return total capital was $5 billion, resulting in a payout ratio of adjusted cash flow from operations of 58%.

As Jim mentioned earlier, we expect an inflection point in discretionary free cash flow in 2026 as we have completed a 4-year period of large investments, both organic and acquisitions that enhanced our — have enhanced and expanded our integrated footprint in the Permian and Haynesville basins and our premium — premier wellhead to market businesses serving domestic as well as international markets via our marine terminals. With the completion of the major projects such as Bahia NGL pipeline, and Neches River Terminal, we continue to believe our organic growth capital expenditures in the near term will return to our mid-cycle range of approximately $2 billion to $2.5 billion per year and largely consist of pipeline expansions and smaller projects, both on the supply and demand side and natural gas storage, treating and processing facilities.

As Jim noted earlier, we announced our Board has approved an increase in our common unit program of — to $5 billion. The program now has $3.6 billion in capacity, allowing us to increase the amount of our annual buybacks as our free cash flow increases. In terms of allocation of capital, we see cash distributions to partners growing commensurate with distributable cash flow per unit in the near term with discretionary free cash flow being evenly split between buybacks and retiring debt. Growth in cash distributions to partners can be further enhanced by the percent of common units we retire through buybacks. Total capital investments were $2 billion in the third quarter of 2025, which included $1.2 billion for growth capital projects, $583 million for the acquisition of natural gas gathering systems from Occidental in the Midland Basin, and $198 million of sustaining capital expenditures.

Our expected range of growth capital expenditures for 2025 and 2026 remains unchanged at approximately $4.5 billion for 2025, and $2.2 billion to $2.5 billion for 2026. We continue to expect 2025 sustaining capital expenditures to be approximately $525 million. Our total debt principal outstanding was approximately $33.9 billion as of September 30, 2025, assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio is approximately 17 years. Our weighted average cost of debt was 4.7% and approximately 96% of our debt was fixed rate. At September 30, we had consolidated liquidity of $3.6 billion, which includes availability under our credit facility and unrestricted cash on hand. Our EBITDA — our adjusted EBITDA was $2.4 billion for the third quarter and $9.9 billion for the last 12 months.

As of September 30, our consolidated leverage ratio is 3.3x on a net basis after adjusting debt for the partial equity treatment of the hybrid debt and reduced by the partnership’s unrestricted cash on hand. This is above our leverage target of 3.3x, plus or minus 0.25 or a range of 2.75 to 3.25x. This is due to the capital expenditures on our large projects such as NGL fractionator 14, Bahia NGL pipeline, Neches River Terminal and the acquisition of Oxy’s Midland gathering system being included in our debt balance without EBITDA included in our trailing 12 months of EBITDA. We believe our leverage will return to our target range by year-end 2026 when we have a full year of EBITDA from these projects. With that, Libby, we can open it up for questions.

Libby Strait: Thank you, Randy. Operator, we are ready to open the line for questions.

Operator: [Operator Instructions] Our first question comes from the line of Jean Ann Salisbury of BofA.

Q&A Session

Jean Ann Salisbury: So there are lots of Permian gas pipelines coming on next year in the basin. Do you think that that’s going to drive producers to produce more gas at the margin? And do you consider that to be a constraint?

Tony Chovanec: The Permian Basin, Jean Ann, is an oil basin, first and foremost, and it will be forever more. I think the thing that more gas pipelines does do is just — and NGLs, transportation takeaway for both NGLs and natural gas at the end of the day, I’ll say, is healthy for the producers, meaning it is healthy for the basin. That’s kind of the bottom line. That’s how we see it, Jean Ann.

Jean Ann Salisbury: That makes sense. And then I think I have one more for you, Tony. I think I know what you’re going to say, but as LPG exports ramp, I’ve gotten this question a lot from people, but do you see Asia rezcom and petchem demand as sort of an unlimited sync for all that LPG? Or is there going to potentially require extreme price pressure on global propane to make it flow?

A. Teague: Jean Ann, I’m going to punt that one to Tug because he travels the world, he and his team. If that’s okay, Tug, can I do that?

Tug Hanley: Yes, this is Tug. Yes, in short, I would say both rezcom demand is growing internationally and petrochemical due to lightening of the petrochemical feed slate. But the growth is really tied to supply. The U.S. will export, what’s needed to balance the market and price will ultimately adjust upon that global demand. So we’re not necessarily worried about demand.

A. Teague: Jean Ann, this is Jim. I’ve got a fundamental that I always believed in. Price creates supply and price creates demand. We’re not going to have an issue with demand.

Tony Chovanec: Jean Ann, while you’re still on the line, I guess I sort of have one for you. You and I have always been in the industry sort of obsessed with this molecule called ethane, as you know. And we haven’t always been on the same side of the ledger relative to this molecule, which now, again, just looking back, has become very important and will become more important. I remember in 2018 at our Analyst meeting, I was on crutches and just after we were at the Museum of Natural Science and sitting on the sidelines, and you came and sat down next to me and you said, “I want to sit next to the only ethane there besides myself in the industry.” Do you remember that?

Jean Ann Salisbury: I do. I remember that Tony.

Tony Chovanec: So what I’d like to say is we’re approaching 1 million barrels a day of exports for ethane. That’s a line of sight that the industry can see. And we still have — just like we talked that day, we still have 600,000 to 800,000 barrels a day that’s being reject.

Jean Ann Salisbury: Yes, it’s unbelievable. Tony, thank you for all of your help over the years. I’m really going to miss working with you.

Tony Chovanec: Thank you, so much.

Operator: Our next question comes from the line of Theresa Chen of Barclays.

Theresa Chen: I’d also like to congratulate Tony on his retirement and thank him for his insights and help over the many years. We wish you the best, Tony. Going to the capital allocation side of things. On the upsized buyback authorization, would you all talk about or just provide more details on the capital allocation outlook for the next couple of years. What do you see at this point as a steady-state run rate for CapEx? And do you expect to buy back stock on a more ratable basis given the visibility in free cash flow growth? Or will it be more opportunistic and dependent on market dynamics?

W. Fowler: Okay. Theresa, this is Randy. Yes, I think when we come in and think about sort of as you put over the near term, the next 2 or 3 years on organic growth CapEx, we do see it in the $2 billion, $2.5 billion range. With the projects that we currently have announced, and with a few that we’ve got pretty good visibility on that we think will come forward that’s included in expectations. Next year, we see really $2.2 billion to $2.5 billion. Could next year get to $2.6 billion, $2.7 billion? It could. But we don’t see it going to $3 billion. And so I think that’s sort of where we are on the CapEx side. And so as a result, we will have — given those numbers, we’ll have some free cash flow to deploy. And again, at this point, looking to split it between buybacks and debt paydown.

And I think because we’re leaning in a little bit more on buybacks than what we’ve done over the last 2 or 3 years, there could be an element of programmatic buybacks in there as well as, I think, with the component of debt paydown that we have in there as well, that gives us a little bit more flexibility to be opportunistic. So really, I see the buybacks having a component of both programmatic and opportunistic.

Theresa Chen: Understood. And with DINO’s announced plans yesterday to potentially move up to 150,000 barrels per day of refined products, primarily from its own refineries from PADD 4 to PADD 5, could this lead to better utilization and/or marketing opportunities on your Texas Western product system that recently went into service and ramped? How do you see this evolving?

Justin Kleiderer: Yes, Theresa, this is Justin. So clearly, a lot of headlines out there with respect to people reacting to kind of the ongoing closures and potential future closures in California. Two points to make. There’s a lot to unpack with respect to the projects out there, whether or not they go or not, and then also what the future closures or potential closures in California will be. But we’ll hang our hat on two things with respect to the system. One is we run a unique corridor pretty much direct to Salt Lake. And to the extent that Salt Lake gets net shorter as a result of these projects, then we’re going to stand to be the beneficiary. And then if you zoom out to our overall product system, both our TW system and our legacy TE system benefit from Mid-Continent pricing being at a premium to the Gulf.

And really, all three of these projects that have been announced do some degree of that. So our overall product system will benefit by — if any of them go. Again, early days, we just have to see how it plays out.

Operator: Our next question comes from the line of Michael Blum of Wells Fargo.

Michael Blum: I also wanted to wish congratulations to Tony. We’ve really enjoyed working with you. So congrats. I wanted to ask kind of a macro question, I guess. So you’re signaling here an inflection point. You’ve completed a big capital build-out phase and now you’re kind of pivoting to some more cash return to shareholders. How much of this is just your view that the macro is less constructive with oil prices lower, drilling slowing, et cetera? Or is it just a function that you think like your system is built out, you’re still expecting that growth, but you just have ample capacity?

W. Fowler: Yes. Michael, I think it’s just a function of large projects. I’ve come back in, and if you look at — if you just look at our history, we have had some large capital-intensive projects that we’ve put into service. And again, our CapEx has flexed up. And then it’s come back into a sort of a normal mid-cycle range. And I think that’s where we are. Probably the most recent cycle of that was in 2015, ’16, where we built the Morgan’s Point ethane export facility. We built the Aegis ethane pipeline running over to South Louisiana, and then we built the Midland-to-ECCO I system. That was a period of elevated CapEx. And then we came back down into sort of a $2.5 billion range until we saw the next large capital project. So I think it’s more of a function of that as opposed to a change in our macro view of the economy.

Michael Blum: Okay. That makes sense. And then on the buyback, I wanted to ask how you’re going to basically balance the potential increase in buybacks with any tax ramifications for your unitholders? And does that create any kind of limit to the amount of buybacks you can do in any given year because of taxes?

W. Fowler: Really, the tax ramifications are really for those selling unitholders, not for the unitholders that remain. Did I answer your question, Michael?

Michael Blum: You did.

Operator: Our next question comes from the line of John Mackay of Goldman Sachs.

John Mackay: Tony, I’m going to make sure we get a few last ones out of you while we still have you. So thank you again. We haven’t really talked about the kind of broader macro that much, the last question kind of touched on it. I’d love just to hear you guys were a little ahead of the curve on being a little cautious earlier this year. I’d love just to hear a little kind of mark-to-market on what you’re thinking now and what you’re hearing from your Permian producer customers.

A. Teague: Is Natalie in here?

Tony Chovanec: Yes. I think Natalie tell us what you’re seeing on our systems would be the best way to start.

Natalie Gayden: Mike, well, this is Natalie Gayden. I would say in Midland, volumes are outperforming our expectations. I think the last time I sat on this call, I gave some well connects just for color. The well connects in ’26 are up 25% from what I told you last time. We’re now expecting almost over 600 wells to be connected to the system next year. A lot of that fourth quarter surge from the original 500. In the Delaware, same growth trajectory. We’ve got a record number of wells being connected to the low-pressure system we’ve built up in the Northern Delaware. That growth curve is steepening for Delaware and the trajectory remains intact and increasingly constructive. And then lastly, I’ll just — I’ll say this, and I may say it more than once, but we don’t talk about base volume durability and PDP and how it holds in on gas.

I think that’s sometimes what people miss, and I’ll just give you an example. We have a producer in Midland that finished their development program a year ago. Today, in Midland, those volumes are flat with where they were then. So in some part of the PDP and the base volume and durability of that volume, I think that’s just upside.

A. Teague: Jay, you got anything on crude oil or Justin on NGLs?

James Bany: Yes. This is Jay on crude. My story is similar to Natalie. Again, we don’t have the same large footprint. We’re probably more heavily weighted to Midland Basin. But from ’24 averages to ’25, we saw a well above a double-digit gain in gathering. And we’re seeing — at least based on producer curves for ’26, something very similar.

A. Teague: How are you contracted on Seminole?

James Bany: Yes. I mean, so we’ve mentioned it, Seminole comes up at the beginning of next year. We do have some space as that pipeline ramps up. But over the course of ’26, we become very well contracted over the year.

Tony Chovanec: I’ll say, again, it will be the last time I’ll say that the PDP wedge is the most underappreciated thing in the industry, particularly when you’re a midstream company. That’s the reality, and we see it time and time again.

John Mackay: Absolutely clear. I appreciate all that color. Second one for me is you talked a little bit about some of these projects coming on maybe a little later than hoped. Could you just give us a general target, $6 billion of projects coming on between now and next couple of quarters. When would you expect those all generally all else equal to be fully ramped?

A. Teague: What was the question? I think you asked when these projects, when would we expect them to be fully ramped that I referred to in my — yes. I think what I said was Bahia will be on at the end of November, 1st of December, Justin. Frac 14 is up and running. PDH 2 was in the process of running. What else was the Neches River Terminal — Tug, you want to take a shot?

Tug Hanley: Yes. This is Tug. Yes, NRT will be — it’s ramping right now. It will be full, call it, by middle of next year, the first train. And then the second train comes online shortly after that, and that will be our LPG ethane flex train, and we’ll have long-term LPG contracts commence once that train starts as well.

A. Teague: Okay. Are you fully contracted on ethane and LPG?

Tug Hanley: We’re around 90% contracted on LPG, and we are fully contracted on ethane…

Operator: Our next question comes from the line of Jeremy Tonet of JPMorgan.

Vrathan Reddy: This is Vrathan Reddy on for Jeremy. I just had one question. I think previous remarks have touched upon the potential for not a major step-up in ’26 organic growth CapEx, but maybe point to the high end, if anything. In that case, curious where in the value chain you see the most attractive opportunities for organic growth? And if you could just expand upon that a little bit.

A. Teague: I’ll take the first shot at it and then let Natalie and maybe Tug. I mean I don’t think we’re through rebuilding gas processing plants. And the appetite we have for exports is stunning. And I think you could see us moving in both directions. Natalie, processing?

Natalie Gayden: Yes. This is Natalie. On processing, if you think about it, there’s 5 Bcf a day under construction, let’s just call it, in the Permian of gas processing capacity in a basin that’s been growing almost 2 Bcf — 2.2 Bcf a day a year. So in the near term, probably call it, 1- to 2-year window, we’ve got clear line of sight to 2 more plants, 2 more 300 a day plants, one beyond what we’ve announced, one in each basin, and we’ve got further expansion opportunities beyond that. And then as we expand our gathering system, our ability to scale with capital efficiency is really rooted in the reach that we already have. So I’ll just leave it there.

W. Fowler: Natalie, do you want to add on what we’re seeing on natural gas power generation in Louisiana and Texas?

Natalie Gayden: Yes. So we’re capturing indirect upside from some of those data — that data center demand really through incremental power gen across Texas and Louisiana. We have an advantaged interconnect footprint in really San Antonio and Dallas area. So we’re well positioned to benefit from that trend without really much incremental CapEx. On the behind-the-meter side, we’ve got several high-margin kind of low-touch opportunities that require minimal investment there, but they offer outsized value uplift.

Tug Hanley: Yes. And this is Tug. Just with respect to ethane specifically on the export side, we’re continuing to see strong international interest for ethane. There’s a lot of demand. So there could be some opportunities there as well.

Operator: Our next question comes from the line of Keith Stanley of Wolfe Research.

Keith Stanley: First, I thought you sounded more optimistic than previously on the PDH issues now being behind you. So am I hearing that right? And can you talk a little more to what gives you confidence after this turnaround that you’re more or less in the clear going forward?

Graham Bacon: This is Graham. On PDH 2, we’ve had some issues with coking on the fourth reactor. As Jim mentioned in his remarks, we’ve developed new operating procedures and made some modifications during the outage to address some of those, and we continue to work with a high-level team from our licensor to improve the process. And if you look at — on PDH 1, if you look at our run rate for the quarter, we had a very high run rate, a few minor issues, but the team out there has really done a great job of being able to reduce some of the impacts, and we know some of the — we’ve got line of sight on fixing a few of the issues that we have. So we’re very optimistic going forward that the PDH run rates are going to continue to increase from where they’ve been, and we’ll see a great improvement in 2026.

Keith Stanley: That’s great to hear. Second one, on your Permian NGL pipelines, can you remind us the business model that you guys pursue here? So is it — you’re primarily transporting NGLs produced at your own plants on your Permian NGL pipelines? Or is there any meaningful amount of third-party NGL volume that you move on your Permian pipes today?

Justin Kleiderer: Keith, it’s Justin. So it’s a portfolio of all of the above, but it’s primarily rooted in the volumes that our gathering and processing plants bring to us. I’ll give you a data point. In 2020, the volumes out of the Permian that our pipelines moved were — 45% of those volumes were from our own gathering and processing facilities. In 2025, that number is now 2/3 of the volume, and we expect that trajectory to continue. We continue to see a growing allocation of our NGL portfolio to be behind our own gas plants. And while we’ll continue to look for other third-party opportunities, we don’t expect that to be our baseline assumption as high — as large as it has been historically.

Operator: Our next question comes from the line of AJ O’Donnell of TPH.

Andrew John O’Donnell: Congrats on your retirement, Tony. I wanted to go back to just some of the NGL and LPG stuff, especially on the terminal volumes. It seems like for the third consecutive quarter, we saw lower implied volumes on the LPG side. I was just wondering if you guys could provide maybe a little bit more detail on kind of what’s going on there, if there’s anything to unpack.

Tug Hanley: Yes, this is Tug. In the third quarter, we had some minor maintenance, which resulted in some lower volumes, and we had some cargoes roll from month-to-month. So nothing other than that. Demand is still strong. It’s robust.

Andrew John O’Donnell: Okay. And then just one other — just continuing on this theme of LPGs. We’re starting to see propane inventories notch new records here. Curious what your view is on the latest for the domestic propane market and maybe if there are any read-throughs on tailwinds for your storage business and/or marketing opportunities you’re looking out over the short to medium term?

Tug Hanley: Contango presents opportunities, we have the storage assets to monetize that, and we will. With respect to lower LPG price that could provide potentially some arbitrage opportunity across the water, those will be the opportunity sets.

A. Teague: How do you see our storage?

Justin Kleiderer: I mean I think Tug is right. We got a lot of storage. We got the biggest storage position in the world. So propane goes contango, it will be beneficial for Enterprise.

Operator: Our next question comes from the line of Manav Gupta of UBS.

Manav Gupta: My first one is on August 6, you announced acquisition of some assets from Oxy. What — how is the integration of those assets going? And the best acquisitions are one which always come with some organic growth opportunity. So if you could highlight the organic growth opportunities on these assets, maybe Athena? What else can be done to further get more revenue and EBITDA out of these assets?

Natalie Gayden: This is Natalie Gayden. That asset acquisition was strategic, and I’ll just — let me just lay it out for everybody that doesn’t remember. It’s a 75,000-acre acreage dedication. It’s got over 1,000 drillable locations. So an opportunity of that scale is quite rare. They bolt — the assets bolt on pretty seamlessly to our existing footprint and extends the reach. We — it will unlock for us an incremental 200 million a day almost immediately, let’s just call those revenues coming to us in really 2027. We love assets that are already producing gas, but then the development for that asset is going to be quite constructive and strong. Like any other asset or footprint that we’ve purchased, again, being in an area and having the reach is the way we get incremental packages of gas onto our system. So we’ve already seen synergies, yes, with the acquisition of that asset.

Zach Strait: Sorry. This is Zach Strait. I’ll also chime in that there’s going to be a pull-through on the NGL side to both Justin’s pipe and our fractionators.

Manav Gupta: My quick follow-up here is you guys did a very smart deal and got in the Permian sour gas opportunity with Pinon. The price was great. How is that opportunity developing along? And are you seeing more producers willing to go in that part of Eddy and Lea County because the gas, oil ratios are favorable, drill for more gas, but then — sorry, more oil and then get this nasty gas. So how is this Permian sour gas opportunity evolving for you after that announcement of that deal?

Natalie Gayden: Yes. We still think Pinon is the most attractive position out there. So we’re so proud of that. There has been a bit of a pacing gap really with producers working through some of the development hurdles they’ve had with commodities this high of H2S. But it’s temporary. The trajectory remains intact. Train 4 is coming online next summer for us. It will add another 180 million a day of treating. We see train 5 and 6 right behind it. So the setup for that system is extremely bullish.

Operator: Our next question comes from the line of Brandon Bingham of Scotiabank.

Brandon Bingham: I was just curious, looking at the Permian more broadly, there’s a lot of announced egress capacity slated to come online over the next, call it, few years. Just wondering what you make of it considering your currently outlined growth expectations for the basin. Is there a chance that some of these projects get sidelined? Or maybe conversely, do you think there is a chance that Permian growth actually accelerates to meet the announced build-out?

A. Teague: It’s Natalie show…

Natalie Gayden: This is Natalie again. So next year, let’s just call it, 4.5 Bcf a day coming online. That will be really nice. I don’t think we’ll see, let’s just call it, late 2026. But as a reminder, Tony kind of pointed out to it a little earlier, this is an oil basin. These gassier benches aren’t being drilled. It’s because of the multi-bench development that these producers are going after some of these gassy zones. So yes, takeaways there is even better for them.

Tony Chovanec: And I’ll say again, it’s very healthy for the basin. Negative gas prices are not healthy for producers.

Brandon Bingham: Okay. Fair enough. And then just one more — just a quick clarifying one. Natalie, I think you were talking about two incremental plants beyond Athena or line of sight to them. Was that something contemplated for 2026 CapEx budget? Or were you just saying there’s just line of sight to those over the next year or 2? Just trying to figure out like what’s currently contemplated in the 2026 CapEx budget, if it’s just Athena or if there’s an incremental one because you guys kind of have that 1- to 2-year cadence — 1 to 2 a year cadence.

W. Fowler: Yes. This is Randy. And our CapEx expectations for ’26, that includes the expectation that we’ll be building a couple of more plants, in addition to what was already announced.

Operator: I would now like to turn the conference back to Libby Strait for closing remarks. Madam?

Libby Strait: That concludes our remarks for today. Thank you to everyone for your participation, and have a good day.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.