Enterprise Products Partners - Earnings Call - Q3 2025

Executive Summary

• Q3 2025 delivered resilient operational growth but lighter financials: Revenue rose to $12.03B (+1.9% vs S&P consensus), GAAP diluted EPS was $0.61 (below consensus), and Adjusted EBITDA was $2.405B (below consensus), pressured by lower processing margins, recontracted LPG loading fees, and PDH/fractionator downtime. Versus Q3 2024, net income fell to $1.356B and EPS to $0.61 from $0.65.
• Significant capital-return catalyst: The Board expanded the buyback authorization from $2.0B to $5.0B, with $3.6B remaining capacity; payout ratio over the last twelve months was 58% of Adjusted CFFO.
• Operations set nine new records; Neches River Terminal Phase 1 started in July, FRAC14 ramped mid-October, and Bahia NGL pipeline is on track for late November, positioning an FCF inflection in 2026 as the multi-year build cycle nears completion.
• Street setup: EPD beat revenue but missed EPS and EBITDA vs S&P consensus; management emphasized sequential tailwinds from project startups and improving PDH run rates into 2026.

What Went Well and What Went Wrong

What Went Well

• Record activity and strong throughput: Record natural gas processing inlet of 8.1 Bcf/d (+6% YoY), natural gas pipeline volumes of 21.0 TBtus/d (+8% YoY), and equivalent pipeline volumes of 13.9MM BPD (+7% YoY).
• Export and pipeline momentum: Ethane export volumes increased at Morgan’s Point/Neches River; Eastern ethane pipelines (ATEX/Aegis) saw higher fees and +109 MBPD volumes; Permian/Rocky NGL pipelines +138 MBPD.
• Strategic capital return: Buyback authorization lifted to $5B with $3.6B remaining; management guided to splitting 2026 discretionary FCF roughly evenly between buybacks and debt paydown.
  • Quote: “We announced a $3.0 billion increase to Enterprise’s common unit buyback program…gives us the ability to increase our annual buybacks as our free cash flow increases” – Jim Teague.

What Went Wrong

• Margin headwinds and downtime: Lower sales/processing margins, recontracted LPG loading fees at EHT, and maintenance at NGL fractionators and PDH units pressured gross operating margin (GOM) and EBITDA; Q3 included $34M MTM hedge losses vs $3M gains in Q3 2024.
• LPG at EHT: Gross operating margin declined by $44M YoY due to lower loading fees; LPG export volumes decreased by 42 MBPD.
• PDH2 reliability: A ~60-day turnaround to address coking issues; while restarting and improving, it deferred contribution from Q3 into late 2025/2026.
  • Analyst concern: EBITDA and EPS missed S&P consensus despite volume strength; Street likely revisits near-term margin trajectory [GetEstimates*].

Transcript

Speaker 5

Thank you for standing by and welcome to Enterprise Products Partners L.P.'s third quarter 2025 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. To remove yourself from the queue, you may press star 11 again. I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

Speaker 8

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.

With that, I'll turn it over to Jim.

Speaker 7

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's been more than a colleague. He's been a dear friend and a guiding force at Enterprise for nearly two decades. His leadership in building our fundamentals and supply appraisals 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. Jim, I really appreciate.

Speaker 3

Those kind words and to all y'all here around the table, I really appreciate y'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 pressure 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 as 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's different this time and giving me the chance to establish a fundamentals team that I've been so honored and frankly humbled to be part of.

Speaker 7

I really mean that.

Speaker 3

I guess last but not least, Corey Johnson, the data science team, what y'all have taught me over the last four years I'll take with me the rest of my life. Thanks to everyone.

Speaker 7

Thank you, sir. I'm about to cry, Tony. Matter results today, we reported adjusted EBITDA of $2.4 billion for the third quarter, generating $1.8 billion of distributable cash flow, providing 1.5 times 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 three-month delay, FRAC14 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 mid-year, 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 PDH1 averaging 95% of nameplate and PDH2 showing similar promise as it resumes operations following a third quarter turnaround to address coking in the fourth reactor, an issue the technology licensor 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 Montgovia face 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 multi-year, multi-billion dollar capital deployment cycle that began in 2022. These strategic investments, including pipelines, marine terminals, and key acquisitions, put us in a great position to capitalize on long-term growth from the Haynesville and Permian basins. Finally, I'm sure Randy's 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. With that, I'll turn it over to Randy.

Speaker 3

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 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 nine 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 nine months of 2025, including 1.2 million common units on the open market for $37 million in the third quarter. For the twelve 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 inflation inflection point in discretionary free cash flow in 2026 as we have completed a four year period of large investments, both organic and acquisitions, that have enhanced and expanded our integrated footprint in the Permian and Haynesville Basins and our 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 the HEA 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 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 Teague noted earlier, we announced our board has approved an increase in our common unit program of $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 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 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 3.3 times on a net basis after adjusting debt for the partial equity, treated the hybrid debt and reduced by the partnership's unrestricted cash on hand. This is above our leverage target of 3.3 times plus or minus a quarter, or a range of 2.75 to 3.25 times. This is due to the capital expenditures on our large projects such as FRAC14, the HEA NGL Pipeline, Neches River Terminal, and the acquisition of Occidental'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.

Speaker 8

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

Speaker 3

Thank you.

Speaker 5

As a reminder to ask a question, you will need to press Star 11 on your telephone to remove yourself from the queue. Please press Star 11 again. Please limit yourself to one question and one follow-up or two questions to allow everyone the opportunity to participate. Please stand by while we compile the Q&A roster. Our first question comes from the line of Jean Ann Salisbury of Barclays. Please go ahead, Jean.

Speaker 0

Good morning. 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? Do you consider that to be a constraint?

Speaker 3

You know the Permian Basin, Gnan is an oil basin first and foremost and it will be forevermore. I think the thing that more gas pipelines does do is just add NGLs transportation takeaway for both NGLs and natural gas. At the end of the day, I'll say it's healthy for the producers, meaning.

Speaker 7

It is healthy for the basin.

Speaker 3

That's kind of the bottom line. That's how we see it. Juan, that makes sense.

Speaker 0

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. Do you see Asia, rescom and petchem demand as sort of an unlimited sink for all that LPG, or is there going to potentially require extreme price pressure on global propane to make it flow?

Speaker 3

You know, Gina, 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? Yeah, this is Tug. In short, I would say both. Rezcom demand is growing internationally and petrochemical due to lightening of the petrochemical feed slate. 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. We're not necessarily worried about demand. This is Jim.

Speaker 7

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.

Speaker 3

Hey Gen, that makes sense. Gen, while you're still online, 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 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 we were at the Museum of Natural Science and sitting there on the sidelines and you came and sat down next to me and you said I want to sit next to the only methane bear besides myself in the industry. You remember that?

Speaker 8

I do. I remember that, Tony.

Speaker 3

What I'd like to say is we're approaching a million barrels a day of exports for ethane. You know, that's a line of sight that the industry can see and we still have it. Just like we talked that day, we still have 600,000 to 800,000 barrels a day that's being rejected.

Speaker 8

Yes, it's unbelievable.

Speaker 0

Tony, thank you for all of your help and time over the years. I'm really going to miss working with you.

Speaker 3

Thank you so much.

Speaker 5

Thank you. Our next question comes from the line of Theresa Chen of Barclays. Your line is open.

Speaker 7

Theresa, good morning.

Speaker 1

I'd also like to congratulate Tony Chovanec on his retirement and thank him for his insights and help over the many years. We wish you the best, Tony.

Speaker 3

Thank you, Theresa.

Speaker 1

Going to the capital allocation side of things on the upside buyback authorization, would you 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?

Speaker 7

Okay.

Speaker 3

Theresa, this is Randy. Yeah, I think when we come in and think about sort of as you put over the near term, the next two or three years on organic growth CapEx, we do see it in the $2 billion to $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 $2.627 billion? It could, but we don't see it going to $3 billion. I think that's sort of where we are on the CapEx side. As a result, given those numbers, we'll have some free cash flow to deploy. At this point, looking to split it between buybacks and debt pay down.

I think because we're leaning in a little bit more on buybacks than what we've done over the last two or three years, there could be an element of programmatic buybacks in there as well. With the component of debt pay down that we have in there as well, that gives us a little bit more flexibility to be opportunistic. I see the buybacks having a component of both programmatic and opportunistic.

Speaker 1

Understood, thank you. With Dyno'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?

Speaker 4

Yeah, Theresa, this is Justin. Clearly, a lot of headlines out there with respect to people reacting to 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 also what the future closures or potential closures in California will be. 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. To the extent that Salt Lake gets net shorter as a result of these projects, we're going to stand to be the beneficiary. 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.

Really, all three of these projects that have been announced do some degree of that. Our overall product system will benefit if any of them go. Again, early days, so we'll just have to see how it plays out.

Speaker 1

That's very helpful. Thank you.

Speaker 5

Thank you. Our next question comes from the line of Michael Blum of Wells Fargo. Your question please, Michael.

Speaker 3

Thanks. Good morning. I also wanted to wish congratulations to Tony. We really enjoyed working with you. Congrats.

Speaker 7

Thank you.

Speaker 3

Thank you.

Speaker 7

Michael, wanted to ask kind of a question.

Speaker 3

Macro question, I guess. 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, cash return to shareholders. How much of this is just your view that the macro is less constructive? Oil prices lower, drilling slowing, etc. Is it just a function that you think your system is built out, you're still expecting that growth but you just have ample capacity? Yeah, Michael, I think it's just a function of large projects. I 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 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, 2016, 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 Echo One system. That was a period of elevated CapEx. We came back down into sort of a $2.5 billion range until we saw the next large capital project. I think it's more of a function that as opposed to a change in our macro view of the economy. Okay, thanks for that. Makes sense.

Speaker 7

On the buyback, wanted to ask how you're going to basically balance.

Speaker 3

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?

Speaker 7

Thanks.

Speaker 3

Really, the tax ramifications are really for those selling unitholders, not for the unitholders that remain.

Speaker 7

Thank you.

Speaker 3

Did I answer your question, Michael?

Speaker 5

You did.

Speaker 7

Thank you.

Speaker 3

Okay, thank you.

Speaker 5

Our next question comes from the line of John Mackay of Goldman Sachs. Please go ahead, John.

Speaker 3

Hey, good morning everyone. Thank you for the time, Tony. I'm going to make sure we get a few last ones out of you while we still have you. Thank you again.

Speaker 7

Thank you.

Speaker 3

We haven't really talked about the 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 they're thinking now and what you're hearing from your Permian producer customers.

Speaker 7

Is Natalie in here?

Speaker 3

Yeah, I think, Natalie, tell us what you're seeing on our systems would be the best way to start.

Speaker 8

Hey, Michael, 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. Well connects in 2026 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 is 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 that trajectory remains intact and increasingly constructive. Lastly, I'll say this, and I may say it more than once, we don't talk about base volume durability and PDP and how it holds in on gas.

I think that 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. In some part of the PDP and the base volume and durability of that volume, I think that's just upside down.

Speaker 7

Jay, you got anything on crude oil or Justin on NGLs?

Speaker 3

Yeah, 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. From 2024 averages to 2025, we saw well above a double-digit gain in gathering, and we're seeing at least based on producer curves for 2026, something very similar.

Speaker 7

How are you contracted on Seminole?

Speaker 3

Yeah, I mean, we've mentioned it. Seminole comes up at the beginning of next year. We do have some space as that pipeline ramps up. Over the course of 2026, we become very well contracted over the year. I'll say again, it'll be the last.

Speaker 7

Time I say it.

Speaker 3

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. That's absolutely clear. I appreciate all that color. Second one from me is.

Speaker 6

Talked a.

Speaker 3

Little bit about some of these projects coming on maybe a little later than hoped. Could you just give us a general target, you know, $6 billion of projects coming on between now and, you know, next couple quarters. When would you expect those all generally all SQL to be fully ramped?

Speaker 7

What was the question? I think you asked when did these projects, when would we expect them to be fully ramped? That I referred to in my—yeah, I think what I said was Bahia will be on at end of November, 1st December. Justin, okay, FRAC14 is up and running. PDH2 was in the process of.

Speaker 3

Running.

Speaker 7

What else was the FRAC14?

Speaker 3

River Terminal came up in July.

Speaker 7

Take a shot, Tug.

Speaker 3

Yeah, this is Tug. NRT will be, it's ramping right now. It'll be full, call it by the middle of next year, the first train, and then the second train comes online shortly after that. That'll be our LPG ethane flex train, and we'll have long-term LPG contracts commenced once that train starts as well. Okay.

Speaker 7

Are you fully contracted on ethane and LPG?

Speaker 3

We're around 90% contracted on LPG, and we are fully contracted on that thing for term. Appreciate the caller, thank you.

Speaker 5

Thank you. Our next question comes from the line of Jeremy Tonet of J.P. Morgan. Your question please, Jeremy.

Speaker 3

Hey, good morning guys. This is Brothan Ready on for Jeremy. I just had one question. I think previous remarks had touched upon the potential for not a major step up in 2026 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. If you could just expand upon that a little bit, I'll take a.

Speaker 7

First shot at it and then let Natalie and maybe Tug. I mean, you know, I don't think we're building gas processing plants and the appetite we have for exports is stunning. I think you could see us moving in both directions. Natalie, processing.

Speaker 8

Yeah, 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. In the near term, probably call it one to two year window, we've got clear line of sight to two more plants, two more 300 a day plants, one beyond what we've announced, one in each basin, and we've got further expansion opportunities beyond that. As we expand our gathering system, our ability to scale with capital efficiency is really rooted in the reach that we already have. I'll just leave it there.

Speaker 3

Natalie, you want to add on what we're seeing on natural gas-fired power generation in Louisiana, Texas?

Speaker 8

We're capturing indirect upside from some of that data center demand really through incremental power generation across Texas and Louisiana. We have an advantaged interconnect footprint in the San Antonio and Dallas area. 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 opportunities for value uplift.

Speaker 3

Yeah, and this is 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. Got it. Very helpful.

Speaker 7

Thank you, guys.

Speaker 3

Thank you.

Speaker 5

Our next question comes from the line of Keith Stanley of Wolfe Research. Please go ahead. Keith.

Speaker 4

Hi, good morning. First, I thought you sounded more optimistic than previously on the PDH2 plant issues now being behind you. Am I hearing that right? Can you talk a little more to what gives you confidence after this turnaround that you're more or less in?

Speaker 3

The clear going forward? This is Graham Bacon on PDH2.

Speaker 7

We've had some issues with coking on.

Speaker 3

The fourth reactor, as Jim Teague 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 licenser to improve the process.

Speaker 7

If you look at PDH1, if.

Speaker 3

You look at our run rate for the quarter, we had a very high run rate, a few minor issues.

Speaker 7

The team out there has really.

Speaker 3

Done a great job of being able to reduce some of the impacts.

Speaker 7

We know some of the we've got.

Speaker 3

Line of sight on fixing a few.

Speaker 7

Of the issues that we have.

Speaker 3

We are 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.

Speaker 4

That's great to hear. Second one on your Permian NGL pipelines, can you remind us the business model that you guys pursue here? 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? Hey Keith, it's Justin.

Speaker 3

It's a portfolio of all of.

Speaker 4

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.

Speaker 3

45%.

Speaker 4

Of those volumes were from our own gathering and processing facilities. In 2025, that number is now two thirds of the volume. We expect that trajectory to continue. We continue to see a growing allocation of our NGL portfolio to be behind our own gas plants. While we'll continue to look for other third party opportunities, we don't expect that to be our baseline assumption as large as it's been historically. That's a very helpful data point.

Speaker 7

Thank you.

Speaker 3

Thank you.

Speaker 5

Our next question comes from the line of AJ O'Donnell of TPH. Please go ahead, AJ.

Speaker 3

Morning everyone and congrats on your retirement, Tony. Thank you. I wanted to go back to just some of the NGL and LPG stuff, especially on the terminal volumes. It seemed like for the third consecutive quarter we saw lower implied volumes on the LPG side. 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. Yeah, 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. Nothing other than that. Demand's still strong, it's robust. Okay.

Speaker 7

Just one other.

Speaker 3

Just continuing on this theme of LPGs, you know, 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. If 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 would be the opportunity sets.

Speaker 7

Okay, thanks guys. How do you see our storage?

Speaker 3

I mean, I think Doug's right.

Speaker 4

We got a lot of storage.

Speaker 3

We got the biggest storage position in the world.

Speaker 7

Propane goes contango.

Speaker 3

It would be beneficial for Enterprise. Great, appreciate the detail. Thank you.

Speaker 5

Thank you. Our next question comes from the line of Manav Gupta of UBS. Please go ahead. Manav.

Speaker 8

Good morning.

Speaker 6

Thank you for taking my questions. My first one is on August 6th you announced acquisition of some assets from Occidental. How is the integration of those assets going? The best acquisitions are ones which always come with some organic growth opportunity. If you could highlight the organic growth opportunities on these assets, maybe ethane or what else can be done to further get more revenue and EBITDA out of these assets?

Speaker 8

Hey, this is Natalie Gayden. That asset acquisition was strategic. 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. An opportunity of that scale is quite rare. The assets bolt on pretty seamlessly to our existing footprint and extend the reach. 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. We've already seen synergies with the acquisition of that asset.

Speaker 1

Perfect.

Speaker 3

This is Zach. Sorry.

Speaker 4

Also chime in that there's going to be a pull through on the NGL side to both Justin's pipe and our fractionators.

Speaker 6

Thank you. My quick follow-up here is you guys did a very smart deal and got in the Permian sour gas opportunity with Pinion. 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 Lee County because the gas oil ratios are favorable, drill for more gas, but then, sorry, more oil and then get this nasty gas. How is this Permian sour gas opportunity evolving for you after that announcement of that deal? Thank you.

Speaker 8

Yeah. We still think Permian's the most attractive position out there. 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. The setup for that system is extremely bullish.

Speaker 6

Thank you so much.

Speaker 3

Thank you.

Speaker 5

Our next question comes from the line of Brandon Bingham of Scotiabank. Your line is open, Brandon.

Speaker 3

Hey, good morning.

Speaker 2

Thanks for taking the questions. I was just curious, you know, 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.

Speaker 3

Just wondering what you make of it.

Speaker 2

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?

Speaker 8

This is Natalie again. 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. 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. Takeaways there, it's even better for them.

Speaker 3

I'll say again, it's very healthy for the basin. Negative gas prices are not healthy for producers.

Speaker 2

Okay, fair enough. 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 the 2026 CapEx budget, or were you just saying there's just line of sight to those over the next year or two? Just trying to figure out 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 one to two year cadence.

Speaker 3

One to two a year cadence. Yeah. This is Randy, and our CapEx expectations for 2026, that includes the expectations that we'll be building a couple of more plants in addition to what announced. Perfect.

Speaker 7

Thank you.

Speaker 5

Thank you. I would now like to turn the conference back to Libby Strait for closing remarks.

Speaker 8

Madam, that concludes our remarks for today. Thank you to everyone for your participation, and have a good day.

Speaker 5

This concludes today's conference call. Thank you for participating. You may now disconnect.