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DATE

Monday, July 28, 2025, at 10 a.m. ET

CALL PARTICIPANTS

  • Co-Chief Executive Officer — Jim Teague
  • Co-Chief Executive Officer & Chief Financial Officer — W. Randall Fowler
  • Senior Vice President, Petrochemical Marketing — Chris D'Anna
  • Senior Vice President, Fundamentals and Supply Appraisal — Tony Chovanec
  • Senior Vice President, Commercial — Tug Hanley
  • Vice President, Commercial — Natalie Gayden
  • Vice President, Commercial — Doug [surname not provided]
  • Vice President, Crude, NGL, and Refined Products Business Development — Justin Kleiderer
  • Vice President, Investor Relations — Libby Strait
  • Vice President, Natural Gas Assets — Evelyn [surname not provided]

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RISKS

  • Co-Chief Executive Officer Jim Teague stated, "our gross operating margin declined by $37 million" on higher LPG export volumes during fiscal Q2 2025, citing "recontracting of a legacy ten-year double-digit term agreement to the current market pricing and by a 60% drop in spot rates."
  • Vice President Doug said, "you really compromised the U.S. brand for reliable supply and energy security" due to BIS restrictions on ethane exports, noting a non-Chinese client switched to naphtha after the incident.
  • Senior Vice President Chris D'Anna confirmed, "We haven't met expectations about what our on-stream time should be." for PDH operations, and reported "pressure from China" and "weakness" in SpreadSpace businesses due to additional global capacity.

TAKEAWAYS

  • Adjusted EBITDA: Adjusted EBITDA was $2.4 billion for fiscal Q2 2025.
  • Distributable cash flow: $1.9 billion, up $127 million or 7% compared to fiscal Q2 2024, with $748 million of distributable cash flow retained.
  • Distribution: 54.5¢ per common unit, a 3.8% increase, to be paid August 14, 2025, to holders of record as of July 31, 2025.
  • Net income: Net income attributable to common unitholders was $1.4 billion, flat year-over-year compared to fiscal Q2 2024, while per unit net income increased 3% to 66¢ compared to 64¢ for fiscal Q2 2024.
  • Buybacks: Three point six million common units repurchased for $110 million; twelve-month total buybacks of $309 million for the period ended June 30, 2025, and total buybacks under the $2 billion program reached approximately $1.3 billion as of June 30, 2025.
  • Coverage: Distribution coverage ratio of 1.6 times.
  • Leverage: Net leverage of 3.1 times as of June 30, 2025, with a target of three times plus or minus 0.25 turns; total outstanding debt of $33.1 billion as of June 30, 2025.
  • Growth capital: Fiscal 2025-2026 growth capital expenditures range reaffirmed at $4 billion-$4.5 billion for 2025 and $2 billion-$2.5 billion for 2026.
  • Liquidity: $5.1 billion in consolidated liquidity at quarter-end, including availability and unrestricted cash.
  • Operational records: Processed 7.8 billion cubic feet per day of natural gas and moved 20 billion cubic feet per day through pipelines in the second quarter, transporting over one million barrels per day of refined products and petrochemicals.
  • Asset growth: Nearly $6 billion in organic growth projects entering service, including two new Permian gas plants ramping and a third plant expected to start up early next year, targeting total Permian processing capacity of nearly five billion cubic feet per day upon completion of all three plants and 650,000 barrels per day of liquids from Permian processing.
  • Contracting: Senior Vice President Tug Hanley stated, "we are 85%-90% contracted on LPG exports through the end of the decade," and Jim Teague and Doug emphasized that facilities will be full despite margin compression.
  • Neches River terminal: Initial operations at the Neches River terminal began with ethane loading capacity of 120,000 barrels per day, expanding in the first half of 2026 by 180,000 barrels per day of ethane or 360,000 barrels per day of propane capacity.
  • Shareholder alignment: Employees, retirees, and their families collectively owned over forty million EPD units as of Dec. 31, 2024, accounting for nearly 2% of outstanding units, making them the second largest unitholder.

SUMMARY

Enterprise Products Partners(EPD 0.21%) management reported persistent margin pressure in the LPG export segment due to market-driven recontracting and spot rate declines, emphasizing volume gains to help offset the impact. The partnership confirmed that multi-billion dollar pipeline and processing expansions are either ramping quickly or set to begin operating within the next year, with the majority of new Permian capacity already reaching high utilization. Capital returns included dividend increases, unit buybacks, and substantial distributable cash flow retention, while management reiterated a steady multi-year capital investment plan and a net leverage ratio in line with stated targets.

  • Senior Vice President Tug Hanley said, "It's all built on infrastructure," highlighting a field-based contracting strategy and the company's ability to sign new term agreements even amid competitive LPG dynamics.
  • Vice President Doug stated, "[BIS requirements] have been disrupted," causing at least one non-Chinese contracting partner to opt for naphtha over U.S. ethane due to reliability concerns.
  • Co-Chief Executive Officer & Chief Financial Officer W. Randall Fowler described future capital allocation as "opportunistic" for buybacks in 2025, with the "larger opportunity" expected in 2026 as free cash flow increases materially.
  • Senior Vice President Tony Chovanec projected the Permian Basin will "continuing to get gassier. Really, for years to come," noting that production guidance from E&P customers is expected to remain stable despite widespread bearish industry commentary.
  • W. Randall Fowler noted that rates secured for the Acadian gas system through recent recontracting are "two to three times what we've seen before," enabled by well-timed activity in the Haynesville region.

INDUSTRY GLOSSARY

  • PDH (Propane Dehydrogenation): A chemical process plant producing propylene from propane, often used in the petrochemical segment.
  • BIS: U.S. Department of Commerce Bureau of Industry and Security, relevant for imposing export license rules on energy products.
  • SpreadSpace businesses: Descriptor for Enterprise's octane enhancement and MTBE product lines, which derive margins from regional or global price spreads.
  • Contango: A market condition where future oil prices are higher than current prices, incentivizing storage.
  • PDP (Proved Developed Producing): Oil and gas reserves that are currently producing and have proven, developed status.

Full Conference Call Transcript

Jim Teague: Thank you, Libby. Despite facing considerable headwinds, we delivered another good performance this quarter. Seasonally, the second quarter is always tough, but this time, we also faced macroeconomic and geopolitical challenges. Today, we reported adjusted EBITDA of $2.4 billion, $1.9 billion of distributable cash flow, providing 1.6 times coverage, and we retained $740 million in DCF. We set five volumetric records for the quarter. Processed 7.8 billion cubic feet of natural gas per day, moved 20 billion cubic feet per day through our natural gas pipeline network. We transported over 1 million barrels per day of refined product and petrochemicals. And we have even more plant pipe, frac, and duct capacity coming online over the next eighteen months.

We got nearly $6 billion worth of organic growth projects entering service. Includes two gas processing plants in the Permian that are ramping as we speak. And the third plant that is expected to start up in the first part of next year. Altogether, these three plants will bring our total Permian processing capacity to almost five BCF a day. Producing 650,000 barrels a day of liquids. In the fourth quarter, we expect to start up a 600,000 barrel per day by EYL grade pipeline and our flat 14. These investments bring more volumes into our NGL value chain. We started operations at our Neches River terminal.

Initially, the facility will have the capacity to load ethane at 120,000 barrels a day. The first half of 2026, the facility will be fully operational for the commissioning of a second train that is a flex train. This expansion will increase its capacity by an additional 180,000 barrels a day of ethane or 360,000 barrels a day of propane. This past quarter was dominated by headlines about tariffs and trade. Many of this being close to home, especially regarding ethane and LPG. We managed to navigate these disruptions. That said, we've been clear about the risk of weaponizing US energy exports. These kinds of actions rarely hurt the intended target and often backfire, hurting our own industry more.

We're fortunate this administration understands the importance of energy and global trade even if the commerce department may need a little reminder. Unfortunately, we could face similar challenges in the future. There are growing rumors of midstream companies planning to enter the LPG export market. However, this space has become increasingly competitive and the impact is already evident. Just a year ago, spot terminal fees ranged from 10 to 15¢ per gallon. That is no longer the case. In the second quarter, our LPG export volumes rose by 5 million barrels quarter to quarter. Yet our gross operating margin declined by $37 million.

This was driven by the recontracting of a legacy ten-year double-digit term agreement to the current market pricing and by a 60% drop in spot rates. Although increased throughput across our Houston Ship Channel pipeline system helped mitigate the decline, it doesn't change the fact that this market is fundamentally shifting. Despite the challenges, however, we remain well-positioned to succeed. Our competitive advantage from our existing export infrastructure enables us to meet customer needs through brownfield expansions. Our new build economics simply don't work, and we will aggressively defend our position. The appetite for US ethane and ethylene remains strong in both Asia and Europe. As to octane enhancement, we've seen margins normalize after a few years of outsized earnings.

But the business remains healthy. Lower margins are a product of new supply and a market, not waning demand. Hydrocarbons is a supply-driven business. And our network of assets reflects that. The majority of our capital projects currently under construction directly support our supply strategy. But supply isn't the whole story. What sets us apart is our extensive connectivity to end users. We are directly or indirectly linked to 100% of the ethylene plants in the US and 90% of the refineries East Of The Rockies. Our export business continues to be a key part of our strategy.

With the addition of the Neches River terminal, expanded LPG loading at EHT, and increased ethylene export capability at Morgan's Point, we've taken deliberate steps to enhance and expand our downstream footprint, strengthening our access to global markets. And with that, Randy, I'll turn it over to you.

Randy Fowler: Okay. Thank you, Jim. Good morning, everyone. Starting with the income statement. Net income attributable to common unitholders was $1.4 billion for both the second quarters of 2025 and 2024. Net income to common unit holders on a per unit basis increased 3% to 66¢ per common unit in 2025 compared to 64¢ per common unit for the second quarter of last year, both on a fully diluted basis. Adjusted cash flow from operations, that is cash flow from operations before changes in working capital, was $2.1 billion for both 2025 and 2024.

Distributable cash flow increased $127 million or 7% to $1.9 billion for the second quarter of 2025, primarily due to lower sustaining capital expenditures compared to last year that had a higher level due to modifications and the turnaround at PDH one. Distributable cash flow provided 1.6 times coverage of the distribution declared for the second quarter of this year, and Enterprise retained $748 million of distributable cash flow. For the last twelve months, the partnership has retained $3.4 billion of distributable cash flow. We declared a distribution of 54.5¢ per common unit for the second quarter of 2025, which is a 3.8% increase over the distribution declared for the second quarter of 2024.

The distribution will be paid August 14, to common unit holders of record as of the close of business on July 31. In the second quarter, the partnership purchased approximately 3.6 million common units off the open market for $110 million. Total repurchases for the twelve months ended 06/30/2025 were $309 million or approximately 10 million common units, bringing total purchases under our $2 billion buyback program to approximately $1.3 billion. In addition to buybacks, our reinvestment plan and employee unit purchase plan purchased a combined 5.5 million common units on the open market for $171 million during the last twelve months, including 1.3 million common units on the open market for $41 million during the second quarter of 2025.

I've highlighted on past calls that almost 50% of our employees participate in the employee unit purchase plan. We did some analysis using our 2024 K-1s. At 12/31/2024, as a group, our employees, retirees, and their families owned over 40 million EPD units for almost 2% of outstanding units and made them our second largest unitholder after privately held EFCO at year-end. For the twelve months ending 06/30/2025, Enterprise paid out approximately $600 million in distributions to limited partners, combined with $309 million of common unit repurchases over the same period, Enterprise's total capital return was $4.9 billion resulting in a payout ratio of adjusted cash flow from operations of 57%.

Total capital investments in 2025 were $1.3 billion, which included $1.2 billion for growth capital projects and $117 million of sustaining capital expenditures. Our expected range of growth capital expenditures for 2025 and 2026 remain unchanged at $4 to $4.5 billion for 2025 and $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 $33.1 billion as of 06/30/2025. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately eighteen years. Our weighted average cost of debt was 4.7% and approximately 98% of our debt was fixed rate.

At 06/30/2025, our consolidated liquidity was approximately $5.1 billion, including availability under our credit facilities, and unrestricted cash on hand. Our adjusted EBITDA for the second quarter was $2.4 billion and for the last twelve months was $9.9 billion. As of 06/30/2025, our consolidated leverage was 3.1 times on a net basis after adjusting our debt for the partial equity treatment of our hybrid debt and reduced by the partnership's unrestricted cash on hand. Our leverage target remains at three times plus or minus 0.25 turns. With that, Libby, I think we can open it up for questions. Thank you. Operator, we are ready to open the call 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, you may press 11 again. Please limit yourself to one question and one follow-up, or two questions to allow everyone the opportunity to participate.

Libby Strait: Our first question comes from the line of Spiro Dounis of Citi. Please go ahead, Spiro.

Spiro Dounis: Thanks, operator. Good morning, team. First question, just want to maybe look at the second half of '25. Jim, you mentioned about $6 billion of assets coming online in the second half. Just curious how should we think about the ramp-up of those assets? Are there a lot of volumes behind the systems? We expect these processing plants to come online pretty full as well?

Jim Teague: Zach, what would be your ramp-up on 05/14? 05/14 will come up completely full. NRT will see a ramp as the LECs are ordered and Natalie can chime in, but I think the processing plants are gonna have a pretty quick ramp to them as well.

Natalie Gayden: Yes. That's right. And Delaware and Midland combined is probably around a 90% utilization today, but remember, we just brought those two plants up by the end of the year. Fourth quarter mainly driven, though we're lower shipping. Full and such driven.

Jim Teague: Well, but he'll come up at just

Spiro Dounis: Bahia should come up probably around fifty percent first twelve months, probably closer to 60%. Again, that's middle of fourth quarter start-up, so you won't get a full quarter's contribution until the first quarter of next year. Got it. Got it. All very helpful. Second question, maybe just shifting to capital allocation. Stepped up the buyback a little bit this quarter. I imagine that was in response to just some volatility in the price. But as we sort of look forward, you're still sort of holding off that $2 billion to $2.5 billion for 2026.

So I wonder now as we're approaching that time frame, you know, do you start ratcheting up the buyback in anticipation of 2026 being a lean year or really not until we get into it we see any sort of, let's call it, step change in the buyback program?

Randy Fowler: Hey, Spiro. Good morning. This is Randy. Yeah. We've, you know, we had said, actually last quarter that our expectation this year was we would probably do anywhere from $200 to $300 million of buybacks. You're right. In the second quarter, we did see some volatility and so we picked up the pace of purchases. You know? And I think we'll continue to be opportunistic for the remainder of this year. I think the larger opportunity for the buybacks will come in 2026 as we really start throwing off much more free cash flow.

Spiro Dounis: Great. I'll leave it there. Thanks, everyone.

Libby Strait: Thank you.

Operator: Our next question comes from the line of Jean Ann Salisbury of BofA. Please go ahead, Jean Ann.

Jean Ann Salisbury: Hi. Good morning. I wanted to go back to some of Jim's commentary on the call. LPG export fees have fallen, pipeline and frac might be overbuilt as well and have some pressure there. Do you see this evolving? And how will Enterprise balance defending market share with kind of maintaining your excellent return on capital?

Tug Hanley: Hi, Jean Ann. This is Tug. So it's from our perspective on specifically on LPGs, we stand 85-90% contracted through the balance of the decade. And as far as our strategy, we're all using field economics over here. It's all built on infrastructure, so it allows us to be extremely competitive to continue to get term contracts, which we continue to sign up additional counterparties and will continue to do so.

Jim Teague: You know, Jean Ann, the other thing I think is important is that export facility has a way of being a magnet for our pipelines and our fractionators and our storage.

Jean Ann Salisbury: That makes sense. Thank you. And then I think as my follow-up, it's probably for Tony. There is obviously a lot of concern about potentially slowing oil growth in the Permian next year. If oil growth does slow down or even is flat next year, do you see the rates of gas to oil ratio growth changing, if at all? And how do you think about that?

Tony Chovanec: Good morning, Jean Ann. I think I'll think about that question. First and foremost, we believe the Permian Basin producers have been and will always be looking for oil. That said, they've been drilling about 5,000 locations a year for the last several years. So I would say it's clear that the easiest and oiliest locations for the most part have been drilled up. Thus, we have been and we will be drilling gassier benches and we've talked about that, you know, for the last year or two. You know, you add to that oil naturally declines faster than natural gas does. And we have this very large PDP and very large and growing PDP base in the Permian.

So, Jean Ann, in any way you cut it, all signs point to the Permian Basin continuing to get gassier. Really for years to come. There's no question about it. I think while we're on the topic of the Permian, maybe I'll just talk about how we see the Permian if maybe this is a good time to talk about it. Because there's been a lot of question. What's that?

Jean Ann Salisbury: It's a great time, Tony. Thanks.

Tony Chovanec: You know, there's a lot that's happened over the last sixty to ninety days. First and foremost, OPEC has abandoned their long-standing market stability role in favor of market share, and on the way to putting a couple of 2 million barrels of incremental production on in just a six-month time period. That's a lot. Then we had the Israel and Iran conflict break out to a full-fledged war. And all the oil facilities in Iran and throughout The Middle East were unscathed, so thus we had the war premium taken out. So all that being said, there's a lot of pressure one could see on oil. Meanwhile, you know, we're sitting here in summer driving season around the world.

And strong demand in The Middle East. So the question is when does strong demand end, summer driving season ends, and The Middle East stops using all the oil for electrical generation. What happens to oil? And, you know, I guess, Jean Ann, respectfully, I see there's a lot of people that have some pretty dire forecasts. And we feel differently. And I think and I'll just point out the reason we feel differently is OPEC's been shorting the market at least 2 million barrels a day for two years running and more on top of that. So there is a massive hole to be able to put oil into when and if the price drops.

So assuming we have a price drop and if we move from backwardation to contango, oil's gonna get a signal to trade and into storage, and that's the way we see it. So, you know, we're probably not as bearish on price although we don't have to call price. We're not as bearish as others. But from a fundamental standpoint, I will say we're not as bearish as others. So what does that mean for US producers? We had a brief period where we touched $57. But, you know, we're at $65 this morning. And, really, when you look at 26, 27, all the way up to 30, we're at $62 to $63.

For the Permian producer, which is where we're focused with our assets, you had the improvement in gas basis because of new pipelines to take away and really, Jean Ann, Permian producers' bottom line is extremely profitable. So I think what we're gonna see during earning season for producers is you're gonna see them hold their guidance and not go down while others are saying the Permian is gonna be flat to down. We just don't believe that's gonna happen. You'll see them hold their guidance for the year, and you'll see that they've been aggressive in the catching 25, 26, and maybe even some of them 27. From a fundamental standpoint, that's how we see it.

Natalie, what are you seeing then?

Natalie Gayden: Yeah. We are not hearing anything different than what we spoke to in our last call. We actually did get a surprise from one of our producers who bought wells for 2026 in their production plans. There are a few production areas too in our portfolio where it's not declining as expected. And I'll just leave you with this. In Midland, this year, we will have brought on 463 wells. Next year, we will have 498 on the schedule. Just give me some color.

Jean Ann Salisbury: Oh, that's super helpful. Thank you, Tony. You've had a really good record at your forecasting, so that carries some weight. So thank you for the very good answer.

Tony Chovanec: Thank you.

Operator: Thank you. Our next question comes from the line of Theresa Chen of Barclays. Please go ahead, Theresa.

Theresa Chen: Good morning. I want to go back to the topic of NGL exports, and specifically, what are the lessons you've learned from the BIS ethane incident during the second quarter? Do you think the views of your customers, suppliers, and other stakeholders on U.S. ethane exports to China have structurally changed as a result of this event? And if so, are you likely going to try to find alternate markets or end uses for incremental ethane exports from here?

Tug Hanley: Doug, do you want to take it?

Doug: Yeah. So, you know, if you look at what happened with the BIS requiring export licenses effectively for ethane, I will say we were largely unscathed at Enterprise, but I'll remind you that we have a lot of international exposure to other countries other than China. Call it Vietnam, Thailand, India, Europe, Mexico, Brazil. But if it was gonna be sustained, I could see it presenting a challenge for ethane structurally here in the U.S. But what it has done and where it's been a problem is you really compromised the U.S. brand for reliable supply and energy security. When you just cut off a counterparty like that.

In fact, I will tell you we had a non-Chinese based company that we're in discussions with about contracting ethane with. And they've now since made a decision to contract naphtha, which is supplied globally versus just coming to the U.S. to get ethane. So from that perspective, it's been disrupted. But in the short term, we're able to manage through it with our diverse contract mix.

Theresa Chen: Thank you. Then within the petchem and refined product services segment, what's your forward outlook for PDH? As well as, you know, what is your view for whether it be the second half or into 2026 about the SpreadSpace businesses? Can you touch a little bit on the incremental supply you've seen opting that will from here?

Chris D'Anna: Yeah. Sure, Theresa. This is Chris. As far as PDHs go, our operating rates have improved quite a bit versus the first quarter. That being said, we're still not happy in it. We haven't met expectations about what our on-stream time should be. As far as our beef and octane enhancement goes, we've had really a record last three years of high margins and as Jim touched on in the opening remarks, we've kind of returned to historic kind of margins. So they're still really good. I mean, still some of the best margins we have in the company. But it's not what we have had historically.

That being said, you know, so far for the month of July, we've seen margins improve just, you know, part of that probably being driving season. We still see the pressure from China. You know, historically, MTBE was more of a regional market where occasionally, you would see some cargoes coming from Europe or from Asia, and occasionally, we would send some cargoes to Europe or Asia, but by and large, it was regional. That's changed with all the additional capacity coming on from China, we've started seeing that pressure. And that's some of the reason why we've seen some weakness.

Theresa Chen: Thank you.

Operator: Thank you. Our next question comes from John Mackay of Goldman Sachs. Your line is open, John.

John Mackay: Hey. Good morning, everyone. Thank you for the time. I want to get back to the margin compression conversation. I think the narrative around the LPG export hub is clear. I guess if you could just comment, you know, where do you stand in that process? For repricing down those LPG exports? Was that kind of in there now, or is there maybe a little bit more to work through? Then maybe any comment you can make on a related side for anywhere else in the portfolio, but particularly the Permian NGL pipes. Thanks.

Jim Teague: I'll take it and then, Doug, you take it. I think you heard Tug say we're 85-90% contracted on LPG exports through the end of the decade. We're gonna be full. Pure and simple. And we'll defend it however we have to. And Doug, you got anything to add other than we're damn well gonna be full?

Doug: No. We're full. We are full. We're a continued contract pool, but I'll just tell you that we're still executing contracts. So whatever we're gonna lose on margin compression, we're gonna make up by volume.

John Mackay: And then just anything you can add on the Permian NGL pipe side?

Justin Kleiderer: Yeah, John. This is Justin. I would say generally, on TNF, we have very little recontracting to work through to the balance of the decade. You know, at our core, we still expect production to grow. So long as supply growth is happening, we don't expect recontracting to play a role because we're going to continue to see volumes increase.

John Mackay: Alright. That's clear, guys. Appreciate it. I'll leave it there. Thank you.

Libby Strait: Thank you.

Operator: And the next call is from Michael Blum of Wells Fargo. Michael, please make sure your line is unmuted. And if you're not on speakerphone, lift your handset.

Michael Blum: Hey. Can you hear me?

Operator: Yes, sir. Please proceed.

Michael Blum: Great. Thanks, and good morning, everyone. Been reading a little bit about potentially an uptick in activity in the San Juan Basin. I'm just wondering if there's much to that. Are you seeing anything different from your producer customers up there? And could that have a meaningful impact for you guys?

Evelyn: Not necessarily where we are located. I guess the uptick in I don't know if you're talking about the recent acquisition of a player there. As far as we can tell, our San Juan's pretty stable flat to slight really small growth.

Michael Blum: Okay. Great. Appreciate that. And then just maybe just to follow-up for Tony. Appreciate all the commentary. Is it fair to say if I think back to your I think it was, like, April 1 updated production forecast that if you had to tweak that today, there would be pretty minor tweaks to what you were seeing back in April. Thanks.

Tony Chovanec: Michael, that's a great question. I really appreciate it. Yeah. If we had to tweak it today, given the profitability of the Permian producer, those tweaks would be small. From a Blackwell standpoint, we were calling from '25 through '27. I think we were calling for 800,000 barrels of growth. Could that be seven? Yes. Certainly, it could. If prices did go through a low spot, if we had a fall in prices and we go into contango, and then, you know, waiting for people to start storing, could that be a growth of six? I guess on the outside, it could look. We think we grew 350 last year.

So when producers talk about their guidance as we all listen to their calls, come in, Michael, and they say they're gonna stick to their guidance, and their guidance was 3 to 5% growth in the Permian as a general rule. It's not hard math. It's yeah. I think we're on target, Michael. I think we're on target now. And we've said before that liquids forecast is on target to meet our forecast or, you know, producers continue to drill gas here. So feel great about our liquids forecast also. And then, you know, Natalie's confirmed and Justin's confirmed. Zach has confirmed. That's what we're seeing in the business.

Michael Blum: Thank you.

Tony Chovanec: We're not we're just not as sky is falling scenario. Look. The Permian producer is extremely profitable, especially when you look at what's happened in natural gas bases out there.

Operator: Thank you. Our next question comes from the line of Manav Gupta of UBS. Your line is open, Manav.

Manav Gupta: Good morning, guys. There is a lot of announcements on potential LNG projects and there is a belief that Haynesville Shale could be supplying some of them. Can you talk about your leverage to the Haynesville Shale? Maybe talk about the Acadian gas system a little? Thank you.

Randy Fowler: We so our Acadian gas system, we actually went out for open season on our recontracting efforts on that pipeline, actually, timing is everything, and came up at the right time. So the rates we're gonna achieve on that pipe relative to historical is two to three times what we've seen before. So a little bit more increase in activity, obviously, in the Haynesville with that price of gas. And we'll reap benefits from that.

Manav Gupta: Okay. And quickly, since your CapEx is dropping, can you talk about the criteria as you could possibly look at for possible bolt-on opportunities as a company?

Randy Fowler: Yeah. No. But think, you know, when we came in and sort of gave future guidance 2 to 2.5 billion dollars, that's really taken into consideration some organic growth that we could see in our system in the coming years. Whether it's additional processing plants in the Permian, or something more on the distribution side of the downstream part of our system.

Manav Gupta: Thank you.

Libby Strait: Thank you.

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

Keith Stanley: Hi. Good morning. Wanna clarify some of the earlier questions around LPG exports. So you're 85% to 90% contracted through the end of the decade. Given that, can is it fair to assume the more meaningful recontracting headwinds on margins are now over with at this point?

Tug Hanley: This is Tug, that is correct.

Keith Stanley: Okay. Great. And then had one on Neches River. So the major projects under construction bucket went down $2 billion. From 7.6 to 5.6. It looks like that's two processing plants in phase one of the export facility. You know, that implies the capital cost could be maybe a billion dollars or more for phase one of Neches River. Am I thinking about that right, just as a ballpark?

Tug Hanley: Yeah. That's Keith, that's in the ballpark.

Keith Stanley: Okay. And would phase two be similar to that?

Tug Hanley: Not that much.

Keith Stanley: Okay. Thank you.

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

Brandon Bingham: Hi. Good morning. Thanks for taking the questions. I'd like to go back to capital allocation if we could and maybe ask on the inorganic side and different way. Just given all of the cash in that you guys have and you have your priorities outlined pretty clearly, would you consider maybe increasing activity and equity investments potentially into areas where you currently do not participate or operate any assets, maybe like an LNG or how should we think about all of the cash gen moving forward?

Randy Fowler: I imagine Randy's gonna try to give it to you guys. Yeah. Brandon, I don't see us and I'm trying to read where you're going with your question. Are you asking would we make passive equity investments in LNG facilities?

Brandon Bingham: Right. Like, taking a non-op stake or an equity interest or just another way to deploy capital that maybe hasn't been discussed?

Randy Fowler: No. Yeah.

Brandon Bingham: Fair enough. And then maybe just on 2026 growth spend, could you remind us how much is currently committed? And then where do you see the most pressing need to deploy capital or maybe ask another way, where's the greatest opportunity across your operations right now?

Randy Fowler: Yeah. I think, you know, when we look at that in 2026, that range of $2 billion to $2.5 billion, what's committed is approximately $2.2 billion. And where we go? I really like what we've done. In terms of our ethylene. If I look back a few years, we didn't have anything in ethylene. Now we've got a pretty robust storage distribution and export system. And those fees are cents per pound, not cents per gallon.

Brandon Bingham: Great. Thanks.

Operator: Thank you. Our next question comes from the line of Jason Gabelman of TD Cohen. Please go ahead, Jason.

Jason Gabelman: Hey. Thanks. Good morning. Thanks for taking my questions. I'm afraid I'm gonna ask another one on LPG exports. Trying to understand it more from a strategic standpoint. Given the amount of build-out that the industry is pursuing on LPG exports, have your upstream customers kind of told you that you need to more or less have that egress to compete for additional volumes from them? So is this LPG export build kind of driven by what the customer needs and to keep you competitive and in contracting with those customers?

Tug Hanley: I can't speak for what our competitors are doing relative to their CapEx or how much it costs them to build these greenfield facilities. I can just tell you the success we've had on contracting with our brownfield economics is there. It's you know, you have to remind yourself as well that Enterprise Mont Belvieu is the price point for call it, over 95% of total NGL production in The United States. And that's another competitive advantage we have. And customers there just continue to take the LPG exports from our facility at a competitive fee.

Jim Teague: I think it's worth noting that we've been dealing with the international market since 1983 when we put in an import facility. And since 1999 when we built our export facility. We've created a lot of strong relationships and we've performed. So I don't think I think we've got a rather sticky customer base tied to what we've been able to do in the past.

Jason Gabelman: Okay. And my follow-up is unfortunately, a topic that has also been already asked on, which is capital allocation. And I guess the question is, you know, the midstream sector broadly has had multiple expansion given all of the growth opportunities that they've been pursuing over the past couple of years. How important is it? And as you think about capital allocation moving forward, how to continue to have a robust growth backlog that really competes with other companies in the industry to continue to attract equity investment. And how much of it does that kind of frame your strategic decisions on capital allocation moving forward?

Randy Fowler: You wanna take it? Yeah. Let me I think, first, we feel like we're in a good place. The basins that we operate in, you know, focus on the Permian, focus on the Haynesville. You know, the sectors that we support, the downstream sectors, Petchem is a little soft right now. But, again, they'll cycle through this. So we like our footprint. We like where we are. We think we'll have bolt-on opportunities. From an organic standpoint and an inorganic standpoint. As opportunities arise. You come back in, especially look over the last 2024 and 2025, you know, our CapEx did step up. A lot of that was a step change in capacity.

To be able to come in and be able to support the growth of our E and P customers coming out of the Permian. So I think we're in good shape there. I think we've got some low-cost expansions that we can do on some of those assets that are coming into service. And, we're here for the next couple of years anyway. At that $2 to $2.5 billion. You know, our job is to keep our system reliable, keep it up, and we should throw off a lot of cash flow from those businesses. Where we see opportunities to deploy it, we will. But, honestly, I think discretionary free cash flow is really about to take over.

A step up in 2026, 2027. And that'll give us an opportunity to come and return more capital to our investors.

Jason Gabelman: Okay. Understood. Thanks for the answers.

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

Libby Strait: Thank you to our participants for joining us today. That concludes our remarks. Have a good day.

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