Enterprise (EPD) Q3 2025 Earnings Call Transcript

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DATE

Thursday, October 30, 2025 at 10 a.m. ET

CALL PARTICIPANTS

Co-Chief Executive Officer — Jim Teague

Co-Chief Executive Officer and Chief Financial Officer — Randy Fowler

Executive Vice President, Fundamentals and Supply Appraisal — Tony Chovanec

Executive Vice President, Natural Gas — Natalie Gayden

Senior Vice President, Petrochemicals — Graham Bacon

Senior Vice President, NGLs — Justin Kleiderer

Senior Vice President, NGL Marketing and Marine — Tug Hanley

Vice President, Investor Relations — Libby Strait

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TAKEAWAYS

Adjusted EBITDA -- $2.4 billion in the third quarter, as reported by management.

Distributable Cash Flow (DCF) -- $1.8 billion with a 1.5x coverage ratio in the third quarter; $635 million of DCF retained in the third quarter.

Net Income Attributable to Common Unitholders -- $1.3 billion, representing $0.61 per common unit on a fully diluted basis.

Unit Repurchases -- 2.5 million common units repurchased for $80 million in Q3 2025; cumulative repurchases totaled $250 million (8 million units) in the first nine months of 2025 and $1.4 billion since inception.

Total Distributions Paid -- $4.7 billion distributed to limited partners over the twelve months ending September 30, 2025.

Total Capital Returned -- $5 billion returned to investors, including $313 million in unit repurchases, for the twelve months ending September 30, 2025, equating to a 58% payout ratio of adjusted cash flow from operations.

Buyback Program Expansion -- Buyback authorization increased by $3 billion in Q3 2025, now totaling $5 billion with $3.6 billion remaining capacity.

Growth Capital Expenditures -- $1.2 billion for growth capital projects in the third quarter of 2025; full-year growth capital expenditures guidance is $4.5 billion for 2025 and $2.2–$2.5 billion for 2026.

Sustaining Capital Expenditures -- $198 million in sustaining capital expenditures in the third quarter of 2025; full-year 2025 guidance of approximately $525 million in sustaining capital expenditures remains unchanged.

Major Project Status -- Frac 14 is in service after a three-month delay; Bahia and Seminole pipeline projects are on track for completion in 2025.

PDH Facility Performance -- PDH 1 averaged 95% of nameplate capacity in Q3 2025; PDH 2 resumed operations post-turnaround, addressing coking issues in the fourth reactor.

NGL and LPG Contracting -- Ethane is fully contracted on a term basis, and LPG capacity is approximately 90% contracted for the new Natchez River Terminal trains ramping through mid-2026.

Consolidated Leverage Ratio -- Currently above the target range (attributable to large project spending), with management projecting a return to the target by year-end 2026 as new assets contribute EBITDA.

Debt Profile -- $33.9 billion total debt outstanding; weighted average life of 17 years; cost of debt stood at 4.7% as of September 30, 2025; 96% of debt is fixed rate; $3.6 billion in consolidated liquidity as of September 30, 2025.

Organic Growth CapEx Outlook -- Management expects $2 billion–$2.5 billion per year in organic growth capital expenditures in the near term, with 2026 guidance includes two additional gas processing plants in addition to Athena.

Pipeline Volume Composition -- In 2025, two-thirds of NGL volume from the Permian is supplied by the company’s own gathering and processing facilities, up from 45% in 2020.

Pinion Sour Gas Acquisition -- Train Four coming online next summer, increasing treating capacity by 180 million cubic feet per day, with further expansions planned.

Oxy Midland Gathering Acquisition -- 75,000-acre dedication, 1,000+ drillable locations; expected to deliver 200 million cubic feet per day of incremental volumes by 2027.

LPG Terminal Volumes -- Third quarter LPG volumes impacted by minor maintenance and cargo timing, with management noting no underlying demand weakness.

Propane Storage Position -- Management stated they have “the biggest storage position in the world,” according to Tug Hanley, and stand to benefit if forward propane curves move into contango.

SUMMARY

Enterprise Products Partners (NYSE:EPD) reported adjusted EBITDA of $2.4 billion for Q3 2025 and highlighted completion of key capital projects expected to drive future EBITDA growth. The board authorized a $3 billion increase to the buyback program in Q3 2025, creating a total $5 billion capacity for repurchases alongside rising discretionary free cash flow in 2026. Management confirmed two additional processing plants are included in 2026 capital expectations and substantiated contracting strength on upcoming NGL and LPG assets.

Randy Fowler said, "we expect an inflection point in discretionary free cash flow in 2026" as major projects and acquisitions will have completed their capital investment phase and will begin contributing EBITDA for a full year in 2026.

PDH 2’s operational issues were addressed with new procedures and partnership with the technology licensor, and Graham Bacon indicated “we're very optimistic going forward that the PDH run rates are gonna continue to increase from where they've been.”

The company clarified that it returned a 58% payout ratio of adjusted cash flow from operations through a combination of distributions and unit repurchases during the twelve months ending September 30, 2025.

Senior management described additional long-term LPG contracts commencing once the Natchez River Terminal’s second train starts, with 90% of LPG capacity already contracted as of Q3 2025.

Randy Fowler established that future capital allocation in the near term will involve splitting discretionary free cash flow between buybacks and debt reduction, with a possible “Programmatic and opportunistic.” according to Randy Fowler approach to repurchases.

INDUSTRY GLOSSARY

PDH: Propane dehydrogenation plant, a facility converting propane into propylene, a key petrochemical feedstock.

Bcf: Billion cubic feet, a standard measure of natural gas volume.

Frac: Short for fractionator, a facility that separates mixed natural gas liquids into their component products.

PDP: Proved developed producing, referring to oil and gas reserves that are both proven and currently producing.

Contango: A market condition where forward prices for a commodity are higher than spot prices, enabling storage arbitrage.

Full Conference Call Transcript

Jim 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'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 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 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 of pressure work sincerely. Jim, wanna thank you for years ago when we sat down at your table. Recognizing early on that we had some that we now know is a 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 fundamental 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 y'all have taught me over the last four years, I'll take with me the rest of my life. So thanks to everyone.

Jim Teague: Thank you, sir. Yeah. I'm about to cry, 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 1.5 times coverage. Additionally, we retained $635 million of DCF. When I look at the third quarter results, I'm reminded of the long 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 then 2026. After a three-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 promises. 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 Mont Belvieu 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. Natchez River Terminal is 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 put us in a great position to capitalize on long-term growth from the Haynesville and Permian Basin. Finally, I'm sure Randy's gonna hit this, but I kinda 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 unit holders.

Growing distributions 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.

Randy 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 2025. We declared a distribution of 54.5 cents per common unit for the third quarter of 2025, which is a 3.8% increase over the distribution declared for 2024. The distribution will be paid to common unit holders of record as of the close of business on 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 returned total capital of $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 four-year period of large investments both organic and acquisitions that have enhanced and expanded our integrated footprint in the Permian and the Haynesville basins and our premier wellhead to market business. Serving domestic as well as international markets via our marine terminals.

With the completion of the major projects, such as the Heah NGL pipeline, and Natchez 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 buyback program from $2 billion 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 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 seventeen 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 twelve months. As of September 30, our consolidated leverage ratio on a net basis after adjusting debt for the partial equity treated with 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 three and a quarter times.

This is due to the capital expenditures on our large projects such as NGL fractionator 14, the Heah NGL pipeline, Natchez River terminal, and the acquisition of Oxy's Midland gathering system being included in our debt balance, without EBITDA included in our trailing twelve 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: Thank you. As a reminder, to ask a question, you will need to press 11 on your telephone. To remove yourself from the queue, please press 11 again. Please limit yourself to one question and one follow-up or two questions to allow everyone the opportunity to participate. Our first question comes from the line of Jean Ann Salisbury of BofA. Please go ahead, Jean.

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

Randy Fowler: You know, the Permian Basin, Jean Ann, is an oil basin. First and foremost, and it will be forevermore. I think the thing that more gas pipelines 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 base. That's kind of the bottom line. That's how we see it, Jean.

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

Tony Chovanec: You know, Jean Ann, I'm gonna 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: Yep. This is Tug. Yeah. In short, I would say both ResCom demand is growing internationally. And petrochemical due to lightening of the petrochemical feed slate. But the growth is really tied to supply. The US will what's needed to balance the market and price will ultimately adjust upon that global demand. So we're not we're not necessarily worried about demand.

Jim Teague: Hi, Jean Ann. This is Jim. I've got a fundamental that I always believe in. Price creates supply and price creates demand. I bet we're not gonna have an issue. With demand.

Jean Ann Salisbury: That makes sense. Tony, thank you for all of your help and time over the years. I'm really gonna miss working with you.

Tony Chovanec: Well, thank you so much.

Libby Strait: Thank you.

Operator: Our next question comes from the line of Theresa Chen of Barclays. Your line is open, Theresa.

Theresa Chen: Good morning. 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.

Tony Chovanec: Thank you, Theresa.

Theresa Chen: Going to the capital allocation side of things, on the upside buyback authorization, would you all talk about 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?

Randy Fowler: Okay. 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 to $2.5 billion range. You know, 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 to $2.5 billion. Could next year get to $2.6, $2.7? 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, you know, 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 pay down. And I think because we're leaning in a little bit more on buybacks than what we've done the last two or three years. There could be an element of programmatic buybacks in there as well as, I think, 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. So, really, I see the buybacks having a component of those. Programmatic and opportunistic.

Theresa Chen: Understood. Thank you. And with Zynos announced plans yesterday to potentially move up to 150,000 barrels per day of refined products primarily from its own refineries from past four to five. 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: Yeah. Theresa, this is Justin. So clearly, a lot of headlines out there with respect to people reacting to some of the ongoing closures and potential future closures in California. You know, two points to make. You know, 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, we're gonna 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'll just have to see how it plays out.

Theresa Chen: It's very helpful. Thank you.

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

Michael Blum: Thanks. Good morning, and I also wanted to wish congratulations to Tony. We've really enjoyed working with you. So congrats.

Tony Chovanec: Thank you. Thank you, Michael.

Michael Blum: 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 kinda 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, etcetera? 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?

Randy Fowler: Michael, I think it's just a function of large projects. You know, I'm come back in, and if you look at if you just look at our history, you know, we have had some large capital-intensive projects that we put into service and again, CapEx is 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, '16. Where, you know, 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 ECHO one. 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 a function of that as opposed to a change in our macro view of the economy.

Michael Blum: Okay. Thanks for that. Makes sense. And then on the buyback, wanted to ask how you're gonna 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. Thanks.

Randy Fowler: Really, the tax ramifications are really for those selling unit holders. Not for the unit holders that remain.

Michael Blum: Thanks. Did I answer your question, Michael?

Michael Blum: You did. Thank you.

Randy Fowler: Okay.

Libby Strait: Thank you.

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

John Mackay: Hey. Good morning, everyone. Thank you for the time. Tony, I'm gonna make sure we get a few last ones out of you while we still have you. So thank you again.

Tony Chovanec: Thank you.

John Mackay: Haven't really talked about the kind of broader macro that much. The last question kinda touched on it. I'd love just to hear, you know, 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, you know, what you're hearing from your producer customers?

Jim Teague: Who's is Madeline in his Yeah. I think Natalie tells what you're seeing on our systems. Best way to start.

Natalie Gayden: Hey, Michael. This is Natalie Gayden. I would say in Midland, volumes are up for our expectations. I think the last time I said on this call, I gave some well connects just for color. The WellConnect and 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's 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 we've built up in the Northern Delaware. That growth curve is steepening for Delaware and that 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 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.

Jim Teague: Do have to get anything on crude oil? Or Justin on NGLs?

Justin Kleiderer: Yeah. This is Jay on crude. My story is similar to Natalie. Again, we have the same large footprint. We're probably more heavily weighted to whip Midland Basin. But you know, from 24 averages to 25, we saw well above double-digit gain in gathering. We're seeing in the at least based on producer curves for 26, something very similar.

John Mackay: How are you contracted on Seminole?

Justin Kleiderer: Yeah. I mean, so it's you 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. I'll say again, it'll be the last time I say it, 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: That's definitely absolutely clear. Appreciate all that color. Second one from me is you know, 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?

Jim Teague: I think you asked when do these projects when would we expect them to be fully ramped that I referred to in my yeah. I think what I said was a heel will be on at oh, November December 1, Justin. Right. Okay? Frac 14 is up and running. PDH 2 was in the process of running. What else was it? Our Natchez River terminal. Yeah. I don't wanna take it a shot.

Tug Hanley: Yeah. And this is Tug. Yeah. NRT will be it's ramping right now. It'll be full, call it, by 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 commence once that train starts as well.

Jim 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. Per term.

John Mackay: Alright. Appreciate all the color. Thank you.

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

Robin Ready: Hey. Good morning, guys. This is Robin Ready on for Jeremy. I just had one question. I think previous remarks had touched upon the potential for, you know, 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.

Jim Teague: I'll take a first shot at it and then let Natalie and maybe Tug. I mean, you know, I don't think we're through building gas processing plants. And the appetite we have for exports is stunning. And I think you could see us move in both directions. Natalie, process.

Natalie Gayden: Yeah. This is Natalie. On processing if you think about it, there's five Bcf a day under construction, much call it in the Permian, of gas processing capacity in a basin that's been growing almost two BCF 2.2 BCF a day a year. So 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. 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.

Jim Teague: Natalie, you.

Natalie Gayden: Oh, yeah. So we're capturing indirect upside from some of those data center demand. Really through incremental power gen across Texas and Louisiana. We have an advantage 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 kinda low touch opportunities that require minimal investment there, but they offer outsized value uplift.

Tug Hanley: Yeah. And this is Tug. Just with respect to ethane, specifically. On the export side, we're continuing to see strong international interest for ethane as we a lot of demand. Could be some opportunities there as well.

Robin Ready: Got it. Very helpful. Thank you, guys.

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

Keith Stanley: Hi. Good morning. First, I thought you sounded more optimistic than previously on the PDH issues. Now being behind you. So am I hearing that right? And 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 the PDH 2, we've had some issues with coking on the fourth reactor. As Jim mentioned in the 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.

If 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 gonna continue to increase from where they've been, and I will 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: Hi, Keith. It's Justin. So it's a portfolio of all of the above. But it's primarily rooted in the volumes that the power 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 two-thirds 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.

It's an assumption as high as it's been historically.

Keith Stanley: That's a very helpful data point. Thank you.

Jim Teague: Thank you.

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

AJ O'Donnell: Morning, everyone, and congrats on your retirement, Tony.

Tony Chovanec: Thank you.

AJ O'Donnell: I wanted to go back to just some of the NGL and LPG stuff, especially on the terminal volumes. It seemed like, you know, 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 and kind of what's going on there, if there's anything to unpack.

Tug Hanley: Yeah. This is Tug. In the third quarter, we've had some minor maintenance, which resulted in some lower volumes, and we had some cargos roll from month to month. So nothing other than that. Demand's still strong. It's robust.

AJ O'Donnell: Okay. And then just one other 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.

Tug Hanley: Yeah. If Contango presents opportunities, we have the storage assets to monetize that. And we will. With respect to lower arbitrage opportunity across the water? Those will be the opportunity sets.

Jim Teague: Okay. Thanks, Mike. How do you see our storage?

Tug Hanley: I mean, I think Doug's right. We got a lot of storage. We got the biggest storage position in the world. So propane goes in Contango. It'll be beneficial for Enterprise.

AJ O'Donnell: Great. Appreciate the detail. Thank you.

Operator: Our next question comes from the line of Manav Gupta of UBS. Please go ahead, Manav.

Manav Gupta: Good morning. Thank you for taking my questions. My first one is on August 6, you announced the acquisition of some assets from Oxy. What's the how's the integration of those assets going? And, you know, the best acquisitions are one which always come with some organic growth opportunity. If you could highlight the organic growth opportunities on these assets, Aetna or what else can be done to further get more revenue and EBITDA out of these assets?

Natalie Gayden: Hi. This is Natalie Gayden. That asset acquisition was strategic and I'll just me just lay it out for everybody that doesn't remember. It's a 75,000-acre acreage dedication. It's got over a thousand drillable locations. So an opportunity of that scale is quite rare. They bolt up this the assets bolt on pretty seamlessly to our existing footprint. And extends the reach. It will unlock for us an incremental 200,000,000 a day which 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 gonna 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.

Graham Bacon: Perfect. Exactly. I'll also chime in that there's gonna be a pull through the NGL side to both Justin's pipe and our fractionators.

Manav Gupta: Thank you. My quick follow-up here is, you guys did a very smart deal and got an you know, the Permian sour gas opportunity with Pinyin. 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 it's because the gas power 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? Thank you.

Natalie Gayden: Yeah. I we still think Pinion's 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 h two s. But it's temporary. The trajectory remains intact. Train four is coming online next summer for us. It'll add another 180,000,000 a day of treating. We see train five and six right behind it, so the setup for that system is extremely bullish.

Manav Gupta: Thank you so much.

Jim Teague: Thank you.

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

Brandon Bingham: Hey, good morning. Thanks for taking the questions. 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?

Natalie Gayden: No. This is Natalie again. So next year, let's just call it four and a half Bcf a day coming online. That'll be really nice. I don't think we'll see to get let's call it, late 2026. But as a reminder, Tony kinda pointed out to it a little earlier. This is an oil basin. These gassier benches aren't being drilled. It's because of the multibench development that these producers are going after some of these gassy zones. So yeah, takeaways there. It's even better for them.

Jim Teague: 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 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 two? 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 kinda have that one to two-year cadence. One to two a year cadence.

Randy Fowler: Yeah. This is Randy. And our CapEx expectations for '26, that includes the expectation that we'll be able to be building a couple of more plants. In addition to what already announced.

Brandon Bingham: Perfect. Thank you.

Operator: Thank you. 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.

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