Enterprise Products Partners - Earnings Call - Q2 2025

Executive Summary

• Q2 2025 was resilient operationally with record volumes in gas processing, gas pipeline throughput, and crude oil pipelines; non-GAAP DCF rose 7% to $1.94B and covered the raised $0.545 distribution 1.6x, retaining $748M for growth.
• Headwinds: sharp commodity price declines and margin compression in LPG export fees and octane enhancement reduced reported revenues to $11.36B and pressured petchem margins; EPS per unit was $0.66 vs $0.64 YoY.
• Consensus comparison: Revenue missed Wall Street ($14.18B est vs $11.36B actual) while Primary EPS was roughly in line and EBITDA slightly below; underlying fee-based assets and natural gas marketing offset crude marketing weakness (see Estimates Context) (*Values retrieved from S&P Global).
• Execution catalyst: ~$6B of organic projects entering service in 2H25 (new Permian plants, Frac 14, BYO/Bahia, and Neches River Terminal Phase 1) with quick ramps expected, supporting volume-driven cash flow growth into 2026.
• Regulatory watch: BIS ethane export licensing to China caused short-term dislocations and elevated customer risk perceptions; management navigated near-term impacts but flagged strategic export risks as an ongoing theme.

What Went Well and What Went Wrong

What Went Well

• Record throughput across the system: record natural gas processing inlet (7.8 Bcf/d), natural gas pipelines (20.4 TBtus/d), crude oil pipelines (2.6 MBD), and refined/petchem pipelines (1.0 MBD) underpinning stable cash generation.
• Fee-based strength and gas marketing offset: “The performance of our fee-based assets and natural gas marketing more than offset lower earnings in our crude oil marketing businesses…” (Jim Teague).
• Capex cadence and project ramp: Two new 300 MMcf/d Permian plants commissioned with rapid ramp; NRT Phase 1 began service mid-July enabling ethane loading at 120 MBPD; Frac 14 and Bahia pipeline slated for 4Q. Management expects “Frac 14 will come up completely full,” with Bahia ~50–60% in first 12 months (ramp detail from Q&A).

What Went Wrong

• LPG export fee compression: Gross margin at EHT’s LPG-related activities fell 46% ($37M) on recontracting to current market and ~60% drop in spot rates, despite higher export volumes; spot fee declines were called out on the call.
• Octane enhancement margins normalized: Segment gross margin fell $49M on lower sales margins; management cited new supply and China-driven pressure on MTBE markets as structural headwinds.
• Crude oil marketing softness: Net $14M decline in crude assets/marketing on lower sales volumes; crude marine volumes dropped vs prior year (811 MBPD vs 977 MBPD).

Transcript

Operator (participant)

Thank you for standing by, and welcome to Enterprise Products Partners' second 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.

Libby Strait (VP of Investor Relations)

Good morning, and welcome to the Enterprise Products Partners conference call to discuss second 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.

Jim Teague (Co-CEO)

Thank you. 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 face 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 of DCF. We set five biometric 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 products and petrochemicals. We have even more plant, pipe, frack, and dock capacity coming online over the next 18 months. We have nearly $6 billion worth of organic growth projects entering service.

It includes two gas processing plants in the Permian that are ramping as we speak, and a 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 5 BCF a day, producing 650,000 barrels a day of liquids. In the fourth quarter, we expect to start up the 600,000 barrels per day BYO Y-grade pipeline and our Frac 14. These investments bring more volumes into our NGL value chain. We started operations at our Natchez River Terminal. Initially, the facility will have the capacity to load ethane at 120,000 barrels a day. In the first half of 2026, the facility will be fully operational with 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 these hitting close to home, especially regarding ethane and LPG. We managed to navigate these disruptions. That said, we have been clear about the risk of weaponizing U.S. energy exports. These kinds of actions rarely hurt the intended target and often backfire, hurting our own industry more. We are 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 $0.10-$0.15 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 10-year double-digit term agreement at 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 does not 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 where new-build economics simply do not work, and we will aggressively defend our position. The appetite for U.S. ethane and ethylene remains strong in both Asia and Europe.

As to octane enhancement, we have seen margins normalize after a few years of outsized earnings, but the business remains healthy. Lower margins are a product of new supply in the 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. Supply is not 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 U.S. 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 Natchez River Terminal, expanded LPG loading at EHT, and increased ethylene export capability at Morgan’s Point, we have taken deliberate steps to enhance and expand our downstream footprint, strengthening our access to global markets. With that, Randy, I will turn it over to you.

Randy Fowler (Co-CEO)

Okay. Thank you, Jim. Good morning, everyone. Starting with the income statement, net income attributable to common unit holders 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 $0.66 per common unit in the second quarter of 2025, compared to $0.64 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 the second quarters of 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 a turnaround at PDH1.

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 12 months, the partnership has retained $3.4 billion of distributable cash flow. We declared a distribution of $0.545 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 12 months ended June 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 distribution 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 12 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 December 31, 2024, as a group, our employees, retirees, and their families owned over 40 million EPD units, or almost 2% of outstanding units, and made them our second largest unit holder after privately held EPCO at year-end. For the 12 months ending June 30, 2025, Enterprise paid out approximately $4.6 billion in distributions to limited partners, combined with $309 million of common unit purchases 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 the second quarter of 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 remains unchanged at $4 billion-$4.5 billion for 2025 and $2 billion-$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 June 30, 2025. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately 18 years. Our weighted average cost of debt was 4.7%, and approximately 98% of our debt was fixed rate.

At June 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 12 months was $9.9 billion. As of June 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 3 times plus or minus 0.25 turns. With that, Libby, I think we can open it up for questions.

Libby Strait (VP of Investor Relations)

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

Operator (participant)

Thank you. As a reminder, to ask a question, you will need to press star 1 1 on your telephone. To remove yourself from the queue, you may press star 1 1 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 Spiro Dounis of Citi. Please go ahead, Spiro.

Spiro Dounis (Midstream Analyst)

Thanks, Operator. Morning, team. First question, just want to maybe take a look at the second half of 2025. 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? Should we expect these processing plants to come online pretty full as well?

Jim Teague (Co-CEO)

Zach, what will be your ramp-up on 5/14?

Zach Strait (Senior VP of Unregulated NGLs)

5/14 will come up completely full. NRT will see a ramp as VLECs are ordered, and Natalie can chime in, but I think the processing plants are going to have a pretty quick ramp to them as well.

Natalie Gayden (Senior VP of Natural Gas Assets)

Yes, that's right. Delaware and Midland combined is probably around 90% utilization today, but remember, we just brought those two plants up. By the end of the year, fourth quarter mainly driven, Delaware should be full, and so should Midland.

Jim Teague (Co-CEO)

Will Bahia come up at adjusted?

Zach Strait (Senior VP of Unregulated NGLs)

Bahia should come up. Probably around 50% first 12 months, probably closer to 60%. Again, that's middle of fourth quarter startup, so you won't get a full quarter's contribution until the first quarter of next year.

Spiro Dounis (Midstream Analyst)

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. As we sort of look forward, you're still sort of holding off that $2 billion-$2.5 billion for 2026. I wonder now, as we're approaching that time frame, do you start ratcheting up the buyback in anticipation of 2026 being a lean year? Or really, not till we get into it, do we see any sort of, let's call it, step change in the buyback program?

Randy Fowler (Co-CEO)

Hey, Spiro. Good morning. This is Randy. Yeah. We had said, actually, last quarter, that our expectation this year was we would probably do anywhere from $200 million-$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. 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 (Midstream Analyst)

Great. I'll leave it there. Thanks, everyone.

Operator (participant)

Thank you. Our next question comes from the line of Jean Ann Salisbury, of B of A. Please go ahead, Jean Ann.

Jean Ann Salisbury (Managing Director)

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. How do you see this evolving, and how will Enterprise balance defending market share with kind of maintaining your excellent return on capital?

Tug Hanley (Senior VP of Hydrocarbon Marketing)

Hi, Jean Anne. This is Tug. From our perspective specifically on LPGs, we stand 85%-90% contracted through the balance of the decade. As far as our strategy, we're all using brownfield economics over here. It's all bolt-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 we'll continue to do so.

Jim Teague (Co-CEO)

You know, Jean Anne, 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 (Managing Director)

That makes sense. Thank you. I think as my follow-up, it's probably for Tony. There's 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 rate of gas-to-oil ratio growth changing, if at all? How do you think about that?

Tony Chovanec (EVP of Fundamentals and Supply Appraisal)

Good morning, Jean Anne. 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 for the last year or two. You add to that 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 Anne, 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.

Natalie Gayden (Senior VP of Natural Gas Assets)

It's a great time.

Tony Chovanec (EVP of Fundamentals and Supply Appraisal)

Question. What's that?

Natalie Gayden (Senior VP of Natural Gas Assets)

It's a great time, Tony. Thank you.

Tony Chovanec (EVP of Fundamentals and Supply Appraisal)

Okay. There's a lot that's happened over the last 60 to 90 days. First and foremost, OPEC has abandoned their longstanding market stability role in favor of market share and known a way to put in 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 into a full-fledged war. All the oil facilities in Iran and throughout the Middle East were unscathed, so thus we had the war premium taken out. All that being said, there's a lot of pressure one could see on oil. Meanwhile, we're sitting here in summer driving season around the world and strong demand in the Middle East. The question is, when this strong demand ends, summer driving season ends, the Middle East quits using all the oil for electrical generation, what happens to oil?

I guess, Jean Anne, respectfully, I see there's a lot of people that have some pretty dire forecasts, and we feel differently. I think, and I'll just point out the reason we feel differently. OPEC's been shorting the market. At least 2 million barrels a day for two years running and more on top of that. There is a massive hole to be able to put oil into when and after price drops. Assuming we have a price drop and we move from backwardation to contango, oil's going to get a signal to trade into storage, and that's the way we see it. We're probably not as bearish on price, although we don't have to call price. We're not as bearish as others. From a fundamental standpoint, I will say we're not as bearish as others. What does that mean for U.S. producers?

We had a brief period where we touched $57. We're at $65 this morning. Really, when you look at 2026, 2027, all the way out to 2030, we're at $62-$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. Really, Jean Anne, Permian producers' bottom line is extremely profitable. I think what we're going to see during earning season for producers is you're going to see them hold their guidance and not go down, where others are saying the Permian is going to be flat to down. We just don't believe that's going to happen. You'll see them hold their guidance for the year, and you'll see that they've been aggressive in the catching 2025, 2026, and maybe even some of them 2027. From a fundamental standpoint, that's how we see it.

Natalie, what are you seeing? Are we?

Natalie Gayden (Senior VP of Natural Gas Assets)

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

Jean Ann Salisbury (Managing Director)

Wow. That's super helpful. Thank you, Tony. You've had a really good record at your forecasting, so that carries some weight. Thank you for the good answer.

Tony Chovanec (EVP of Fundamentals and Supply Appraisal)

Thank you.

Operator (participant)

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

Theresa Chen (Senior Analyst of Midstream and Refining Equity Research)

Good morning. I want to go back to the topic of NGL exports. Specifically, what are the lessons 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, do you think those views have structurally changed as a result of this event? If so, are you likely going to try to find alternate markets or end uses for incremental ethane exports from here?

Jim Teague (Co-CEO)

Doug, do you want to take it?

Doug McDowell (Managing Director)

Yeah. So if you look at what happened with the BIS requiring an export license 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. If it was going to be sustained, I could see it presenting a challenge for ethane structurally here in the U.S. What it has done and where it's been a problem is you've 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 were in discussions with about contracting ethane with, and they have now since made a decision to contract NAPTA, which is supplied globally, versus just coming to the U.S.

to get ethane. From that perspective, it's been disruptive, but in the short term, we were able to manage through it with our diverse contract mix.

Theresa Chen (Senior Analyst of Midstream and Refining Equity Research)

Thank you. Within the Petchem and Refined Product Services segment, what's your forward outlook for PDH, as well as what is your view for whether it be the second half or into 2026 about the spread-based businesses? Can you touch a little bit on the incremental supply you see in octane that will persist from here?

Chris D'Anna (Senior VP of Petrochemicals)

Yeah. Sure, Teresa. 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, and 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. They are 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, so far for the month of July, we've seen margins improve, just part of that probably being driving season. We still see the pressure from China.

Historically, MTBE was more of a regional market where occasionally you would see some cargoes coming from Europe or from Asia. Occasionally we would send some cargoes to Europe or Asia, but by and large, it was regional. That has changed with all the additional capacity coming on from China, and we started seeing that pressure. That is some of the reason why we've seen some weakness.

Theresa Chen (Senior Analyst of Midstream and Refining Equity Research)

Thank you.

Operator (participant)

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

John Mackay (VP of Equity Research)

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

Jim Teague (Co-CEO)

I'll take it, and then Tug, 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 going to be full. Pure and simple. We'll defend it however we have to. Tug, you got anything to add other than we're damn well going to be full?

Tug Hanley (Senior VP of Hydrocarbon Marketing)

No, we're full. We are full. We're going to continue to contract full, but I'll just tell you that we're still executing contracts. So whatever we're going to lose on margin compression, we're going to make up by volume.

John Mackay (VP of Equity Research)

Is there anything you can add on the Permian NGL pipe side?

Justin Kleiderer (Senior VP of Pipelines & Terminals)

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. At our core, we still expect production to grow. As long as supply growth is happening, we do not expect recontracting to play a role because we are going to continue to see volumes increase.

John Mackay (VP of Equity Research)

All right. That's clear, guys. I appreciate it. I'll leave it there. Thank you.

Operator (participant)

Thank you. Our next call, Michael Bloom of Wells. Michael, please make sure your line is unmuted. If you're on a speakerphone, lift your handset.

Michael Blum (Managing Director)

Hey, can you hear me?

Operator (participant)

Yes, sir. Please proceed.

Michael Blum (Managing Director)

Great. Thanks. Good morning, everyone. I've 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? Could that have a meaningful impact for you guys?

Jim Teague (Co-CEO)

Natalie?

Natalie Gayden (Senior VP of Natural Gas Assets)

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

Michael Blum (Managing Director)

Okay. Great. Appreciate that. 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 1st 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 (EVP of Fundamentals and Supply Appraisal)

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 for 25-27. 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 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. When producers talk about their guidance, as we all listen to their calls coming, Michael, and they say they're going to stick to their guidance, and their guidance was 3-5% growth in the Permian as a general rule, it's not hard math.

I think we're on target, Michael. I think we're on target. We've said before that our liquids forecast is on target to meet our forecast or producers continue to drill gas here. We feel great about our liquids forecast also. Natalie has confirmed, and Justin's confirmed, Zach has confirmed. That's what we're seeing in the business.

Michael Blum (Managing Director)

Thank you.

Tony Chovanec (EVP of Fundamentals and Supply Appraisal)

We're just not a sky is falling scenario. Look, the Permian producer is extremely profitable, especially when you look at what's happened to natural gas basis out there.

Operator (participant)

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

Manav Gupta (Executive Director)

Good morning, guys. There are 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.

Natalie Gayden (Senior VP of Natural Gas Assets)

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. The rates we are going to achieve on that pipe relative to historical is two to three times what we have seen before. A little bit more increase in activity, obviously, in the Haynesville with gas price of gas. We will reap benefits from that.

Manav Gupta (Executive Director)

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

Randy Fowler (Co-CEO)

Yeah. I think when we came in and sort of gave future guidance of $2 billion to $2.5 billion, 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 (Executive Director)

Thank you.

Operator (participant)

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

Keith Stanley (Equity Research Analyst of Midstream and Natural Gas)

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

Tug Hanley (Senior VP of Hydrocarbon Marketing)

This is Tug. That is correct.

Keith Stanley (Equity Research Analyst of Midstream and Natural Gas)

Okay. Great. I had one on Natchez River. The major projects under construction bucket went down $2 billion from $7.6 billion to $5.6 billion. It looks like that is two processing plants and phase one of the export facility. That implies the capital cost could be maybe $1 billion or more for phase one of Natchez River. Am I thinking about that right, just as a ballpark?

Tug Hanley (Senior VP of Hydrocarbon Marketing)

Yeah. That's in the ballpark.

Keith Stanley (Equity Research Analyst of Midstream and Natural Gas)

Okay. Would phase two be similar to that?

Tug Hanley (Senior VP of Hydrocarbon Marketing)

Not that much.

Keith Stanley (Equity Research Analyst of Midstream and Natural Gas)

Okay. Thank you.

Operator (participant)

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

Brandon Bingham (Associate Director of U.S. Equity Research)

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 in a different way. Just given all of the cash gen 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 just how should we think about all of the cash gen moving forward?

Jim Teague (Co-CEO)

I imagine Randy's going to try to give it to you guys.

Randy Fowler (Co-CEO)

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 (Associate Director of U.S. Equity Research)

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

Jim Teague (Co-CEO)

No.

Randy Fowler (Co-CEO)

Yeah.

Brandon Bingham (Associate Director of U.S. Equity Research)

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

Randy Fowler (Co-CEO)

Yeah. I think when we look at that in 2026, that range of $2 billion-$2.5 billion, what's committed is approximately $2.2 billion.

Jim Teague (Co-CEO)

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. Those fees are cents per pound, not cents per gallon.

Brandon Bingham (Associate Director of U.S. Equity Research)

Great. Thanks.

Operator (participant)

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

Jason Gabelman (Managing Director of Energy Equity Research)

Hey. Thanks. Good morning. Thanks for taking my questions. I'm afraid I'm going to ask another one on LPG exports. Trying to understand it more from a strategic standpoint. Given the amount of buildout 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? Is this LPG export build kind of driven by what the customer needs and to keep you competitive in contracting with those customers?

Tug Hanley (Senior VP of Hydrocarbon Marketing)

This is Tug. 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. It's there. You have to remind yourself as well that Enterprise Mont Belvieu is the pricing point for, call it, over 95% of total NGL production in the United States. That's another competitive advantage we have. Our customers are there to continue to take the LPG exports from our facility at a competitive fee.

Jim Teague (Co-CEO)

I think it's worth noting that we've been dealing in 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 think we've got a rather sticky customer base tied to what we've been able to do in the past.

Jason Gabelman (Managing Director of Energy Equity Research)

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

Jim Teague (Co-CEO)

Go ahead, Teague.

Randy Fowler (Co-CEO)

Yeah. I think. First, we feel like we're in a good place. The basins that we operate in. Focus on the Permian, focus on the Hamesville. The sectors that we support, the downstream sectors, Petchem is a little soft right now, but again, they'll cycle through this. 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. When you come back in, especially look over the last 2024 and 2025, 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&P customers coming out of the Permian. 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. We're here for the next couple of years anyway at that $2 billion-$2.5 billion. 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. Honestly, I think discretionary free cash flow is really about to take a step up in 2026, 2027, and that'll give us an opportunity to come and return more capital to our investors.

Jason Gabelman (Managing Director of Energy Equity Research)

Okay. Understood. Thanks for the answers.

Operator (participant)

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

Libby Strait (VP of Investor Relations)

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

Operator (participant)

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