Enterprise Products Partners L.P. Aktie

Thank you for standing by, and welcome to Enterprise Products Partners LP's First Quarter 2026 Earnings Conference Call. I would now like to hand the call over to Joe Thiriak, Vice President of Finance and Investor Relations. Please go ahead.

Thanks, Latif. Good morning, and welcome to the Enterprise Products Partners conference call to discuss first quarter 2026 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise's General Partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn it over to Jim.

Thank you, Joe. We got off to a very strong start this year, and the business is performing well across the board. In the first quarter, we generated $2.7 billion of EBITDA in a short quarter, and this was up 10% over last year. We generated 1.8x coverage of our distributable cash flow. By any measure, this was an exceptional quarter. The assets we brought online over the past year, including the Bahia NGL pipeline, fractionator 14 and 3 Permian natural gas processing plants continued to ramp throughout the quarter. In fact, frac 14 was full on day 1. The gas plants were essentially full by mid-quarter. And if you look at Bahia and Shin Oak as a system, they are running at 80% of a combined 1.2 million barrels a day of capacity. Operationally, the quarter was outstanding. We set multiple operating records across the system. With the addition of Midtown West 2 in the Delaware Basin during the first quarter, we set a new record for gas processing plant in

[Audio Gap]

volumetric records for the first quarter. Those results speak to both the scale of our system and the demand we are seeing across the markets we serve. On the market side, commodity prices were volatile throughout most of the quarter, and we tend to embrace volatility. In January, Winter storm Farn gave us a strong start to the year. elevated demand for natural gas and propane created price dislocations across our asset network as producers faced widespread supply disruptions following the short drop in temperatures.

Our trucks, pipelines and storage facilities enabled us to continue meeting customer needs despite these challenges while our marketing teams and asset flexibility allowed us to capture incremental value, and this was only the beginning of the volatility we experienced during the quarter.

The ongoing conflict in the Middle East and restricted flows through the strike have driven a substantial increase in demand for all forms of U.S. energy, petrochemicals and refined products. The supply shock dramatically improved U.S. petrochemical margins, prompting our domestic petrochemical customers to run their units full out 1 week before the start started the war in Iran. Ethane to ethylene cracking margins were about $0.07 a pound. Today, they are $0.23. The ethylene to polyethylene spread was $0.20 per pound now over $0.45. It's no wonder when my former employee stock is up over 50% year-to-date.

International demand for U.S. feedstocks is as strong as we have seen in quite some time. The loss of Middle East hydrocarbon supply fractured the Asian supply chain. China's PDHs are currently operating at less than 50% of capacity. As a result, Asian petrochemicals have been destocking inventories by consuming derivative inventories. The impact to hydrocarbon markets around the world has been significant and we see this strong demand continue through the remainder of '26 and maybe into '27.

The demand pool is showing up very clearly in our Marine Export business. Our crude oil terminals are benefiting from volumes being released from the U.S. Strategic Petroleum Reserve that are being directed to international markets. And our ethane and LPG customers continue to line up at our docks for U.S. NGL feedstocks. In the first quarter, we averaged around 70 million barrels per month across our dock, and we expect that strength to continue into the second quarter as we are scheduled to load more than 88 million barrels in April. On the upstream side, we continue to build on the momentum in our system. Producer activity remains constructive in the basins where we operate and our assets are well positioned to capture volume growth.

The combination of strong supply, growing export demand and new projects ramping into service is creating real operating leverage across the business. We also saw strong contributions from the downstream stack. In addition to record product flows, strong margins across our assets and high utilization at our PDH facilities that supported solid earnings and cash flow for the quarter. Our new assets are ramping well volumes are at record levels. Demand remains strong both domestically and internationally, and our system is performing the way it was built to perform.

We entered 2026 expecting steady production growth and oversupplied markets, which we thought would lead to another year of relatively benign commodity prices. That has clearly not been the case. Today, we believe the financial markets are underestimating the potential global supply implications from a prolonged closure of the strata or moves. Depending on the industry expert you ask anywhere from 12 million to 15 million barrels a day of crude oil, refined products, LPG and petrochemical supplies are constrained. That is almost 0.5 billion barrels of hydrocarbon supplies of the market every month.

Shipping and geopolitical commentators estimate that the earliest Strait could reopen for normal operations, including vessel repositioning as July, and that does not account for the time required to repair onshore production and refining facilities damaged in the war. Until global supplies and inventories returned to normal, we believe there will continue to be strong international demand for U.S. energy and products. We are also seeing international consumers look to increase purchases of U.S. Energy is an avenue to improve the U.S. trade balance and add greater resilience in security to their energy supply chains given the current disruption of product flows in the Middle East.

After the first quarter, we are encouraged by the momentum we are seeing across the business and increasingly confident in the outlook for the year. At the same time, we remain focused on what matters most: operating cycling, serving our customers rely on them, allocating capital with discipline and creating long-term value for our investors. With that, I'll turn it over to Andy.

Thank you, Jim, and good morning, everyone. Starting with the income statement items. Net income attributable to common unitholders for the first quarter of 2026 was $1.5 billion, or $0.68 per common unit on a fully diluted basis, which is a 6% increase compared to the first quarter of 2025. Adjusted cash flow from operations which is cash flow from operating activities before changes in working capital increased 10% to $2.3 billion for the first quarter of 2026 compared to $2.1 billion for the first quarter of 2025.

We declared a distribution of $0.55 per common unit for the first quarter of 2026, which is a 2.8% increase over the distribution declared for the first quarter of 2025. The distribution will be paid on April 14 to common unitholders of record as of close of business on April 30. We are on track for 28 consecutive years of distribution growth in 2026. To our knowledge, this is the longest period of distribution growth of any U.S. midstream company and is example of Enterprise's consistency and commitment to returning capital directly to our unitholders.

The partnership purchased 3.1 million common units of the open market during the first quarter for approximately $116 million. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 1 million common units on the open market for $37 million during the first quarter. For the 12 months ended March 31, 2026, enterprise returned approximately [ $5.1 ] billion of capital to our equity investors. 93% or approximately $4.8 billion was in the form of cash distributions to limited partners and the remaining 77% through $356 million of buybacks.

Our payout ratio of adjusted cash flow from operations was 57% over this period. Since our IPO in 1998, we have prioritized returning capital to our partners, returning over $63 billion through distributions and buybacks. At the same time, we have reinvested capital to build one of the largest energy infrastructure networks in North America. Total capital investments were $988 million in the first quarter of 2026, which included $783 million of growth capital projects and $205 million of sustaining capital expenditures.

In the first quarter, we also see the final payment of $596 million from ExxonMobil for the purchase of a 40% interest in the Bahia NGL pipeline. With the completion of major projects such as the Bahia NGL pipeline and Neches River terminal, we believe our expected range of growth capital expenditures for 2026 will net to $2.3 billion to $2.6 billion after applying approximately $600 million in proceeds from asset sales already received. For 2027, we expect our growth capital expenditures to be in the area of $2 billion to $2.5 billion. Sustaining capital expenditures for 2026 are expected to be approximately $580 million.

On the fourth quarter 2025 earnings call, we stated that discretionary free cash flow for 2026 has the potential to be in the $1 billion area. Even though estimate of growth capital expenditures for 2026 has increased by $300 million as a result of investments in 2 new natural gas processing plants in the Permian, we still believe discretionary cash flow for 2026 has to be -- has the potential to be in the $1 billion area. And depending on commodity prices and spreads for the remainder of the year could be higher.

In terms of allocation of capital, as we have said many times, we see cash distributions to partners grow in commensurate with operational distributable cash flow per unit. Let me repeat that, as we have said many times, we think distributions to partners will grow commensurate with operational distributable cash flow per unit growth. In the near term, we continue to expect discretionary free cash flow to be split between buybacks and retiring debt. In 2026, we still expect this slip would be approximately 50% to 60% in buybacks.

As we have said before, Enterprise's buyback program has both programmatic and opportunistic elements. In periods of momentum and volatility characterized by higher equity prices, we may elect not to chase price and instead retain cash in the opportunistic bucket for buybacks in future periods when momentum has on. Similarly, in periods when there are significant price dislocations in equity prices, we may elect to pull cash forward earmark buybacks in future periods, such as bringing cash forward from 2027 to buy back the partnership units at more opportunistic prices in the near term.

Our total debt principal outstanding was approximately [ $34.2 ] billion as of March 31, 2026. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately 17 years. Our weighted average cost of debt was 4.7% and approximately 95% of our debt was fixed. At March 31, our consolidated liquidity was approximately $3.3 billion, including availability on our credit facilities and unrestricted cash on hand.

As Jim mentioned, adjusted EBITDA increased 10% to $2.7 billion for the first quarter of 2026. As of March 31, 2026, our consolidated leverage ratio decreased to 3.2x on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and reduced by the partner's unrestricted cash on hand. Our current leverage ratio reflects significant investments in the large-scale projects that we recently brought into service, such as the Bahia NGL pipeline, Port Neches terminal and frac and the midstream asset acquisition from [ Occidental ], where the debt is on the balance sheet, but the resulting annual adjusted EBITDA generation from these investments is yet to flow into our 12-month trailing EBITDA number. Our overall leverage target remains at 3x plus or minus 0.25x or $2.75 to $3.25 billion. With that, [indiscernible], I think we can open it up to questions.

Thanks, Randy. Latif, we are ready to open the call for questions.

[Operator Instructions]

Our first question comes from the line of Theresa Chen of Barclays.

Following up on the comments about the uptick for U.S. energy demand in general and export infrastructure demand in particular, can you walk us through the contract duration profile across your export docs today? Specifically, how much capacity is tied to contracts with near-term expirations that could be recontracted at higher rates? And longer term, how much incremental brownfield expansion capability do you have across your export assets? .

Theresa, this is Tyler Cott. I'll speak to the NGL exports specifically. I think we've said before, our NGL export docks are contracted around the range of on LPG, those contracts go through the end of this decade on ethane, they extend 1 to 2 years depending on contracts, so lengthy duration. We had 10% available for spot capacity in the near term, but long term, we're significantly contracted.

Okay. And on the LPG side, in particular, given the recent strength in LPG export ARPS, alongside the commissioning time line for Phase 2 of the Neches River expansion, can you talk about incremental earnings uplift or cash uplift from spot cargoes in interim? And related to this, when do you expect Phase II officially enter service to support your term commitments with customers? .

Sure. This is Tyler Cott again. Our operations team has done a fantastic job expediting a bit the commissioning of Matas River terminal. We're still in the process of commissioning it. We began in the second half of April. And at this point, we expect to complete commissioning for both ethane and propane sometime in May.

In terms of spot utilization and earnings uplift, we really got to get through the commissioning process here and see what we have. I think an important point to note about our export business going forward, as we have a significant amount of flexibility, so our spot business will be dictated across different products in terms of what the market needs at a given time. Jay?

Yes. Theresa, this is Jay Baney. Just on the crude front of that, -- we've got a pretty wide mix of contract structures. So contracts that last through '28 and '29. And similar for '26, we have about 10% of open capacity. And yes, I think we're having good conversations about '27.

Our next question comes from the line of Spiro Dounis of Citi.

I want to go back to the growth outlook really quickly, Jim, you sound incrementally more positive than when we last caught up. Obviously, a lot has changed. And then, Randy, you seem to indicate that your operating cash flow is going to have at least sort of mirror the increase in CapEx to keep that DCF free cash flow kind of stable. So Curious if you could give us an update on the sort of 3% growth you guys are talking about for '26 and the 10% growth you were talking about for 2027 on the last call. And as you answer that question, just curious if these 2 new processing plants are additive to that '27 outlook?

This is Jim. Yes, I think I said modest in '26 and 10% and: '27. I think will be modest.

Yes. Spiro, I sort of like the point you made in your note that probably modest is a low bar now. And I think you're right. again, it's sort of hard to come in and look at 2026 because, again, just what's the duration of these commodity price is going to be and the duration of spreads. So really shaping up to be a much stronger year than what we expected. And again, because we were really coming in and not expecting much benefit at all from commodity or spread and really, we're aligned on our fee-based businesses.

So really hard to come in and give much guidance because it's sort of -- you don't have much visibility, especially when you come in and look at the futures market because we don't think the futures market really is representative of what the physical markets should be. So -- but the end point is 2026 looks to be much more favorable year than when we first started. Commercial guys team did a great job in underwriting 2 more natural gas processing plants in the Permian, which really then will come on during 2027.

We really did not have those baked into our 2027 numbers at the time. So that would be additive. And then from the same token, I think we're still in good shape to come in and do meaningful buyback and meaningful debt retirement in 2026 even with CapEx ticking up a little bit for these 2 new plants.

And Sprio, I've been around a while, and I have never seen a supply disruption like we're experiencing today. that supply disruption creates a lot of benefits that Enterprise is able to capture.

Yes. And that's actually a good segue to the second question. Jim, you also talked about embracing volatility. And I know we go back a few years ago, you used to sort of talk about this sort of $500 million or so outsized spread gains you guys would sort of find in any given year, that's been absent for about maybe the last 2 years or so. Just curious, it sounds like that's back. I don't want to put too fine a number on it, but in the environment you're seeing now, do you think we see a return to that $500 million? And what parts of the market do you see that from, obviously, export being a big one?

I don't know -- I don't know if it's going to be $500 million, $600 million or $700 million, frankly. But I do expect that we're going to have what you call outsized spreads. Frankly, typically, we have it every year, we just don't know which spread it will be. Last year was pretty benign and usual for us as to what specifically it might be. I'll throw it to [indiscernible]. .

Yes. This is Doug. I'll just add. I mean, this first quarter, we had some outsized spreads on natural gas, when storm firm presented some opportunities, but largely the spreads that we've seen post Iranian conflict, those will come second quarter. .

Our next question comes from the line of Jean Salisbury of BofA. .

We've talked about this a little bit at the dinner tug, but it seems like international crackers that are running ethane and are pretty happy that they do so right now. Has there been any interest in the last couple of months in more international conversions to than that could drive the next leg of ethane demand?

Yes, this is Doug. So yes, they were happy prior to the conflict and they're even happier now. I will say that interest and demand we've seen on ethane specifically and I'll even throw LPG in there, we had quite the appetite for demand prior to the conflict. And I would say we have the similar appetite for demand post conflict. It made sense before and it still makes sense today. .

That's helpful. And I guess as a follow-up to that question, how -- what's kind of the time line if a cracker does decide to convert to ethane or take more ethane to the ethane being delivered? Should we expect like basically a couple of years for them and you to build that capacity?

That's probably -- it's not overnight, Jean. I think your couple of years is probably in the ballpark.

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

At dinner a few weeks ago, you didn't really think you'd see any cement shifts in where global buyers are going to source their hydrocarbons. I thought maybe they trip more to the U.S., but you seem to think that wouldn't happen. Curious just if that's -- if any -- if you've had any change in your thinking there? And -- in a similar vein, I think at the time, you didn't really think we'd see any reaction from the U.S. producers, and I'm curious if you still think that's the case?

I'll take the second one first, [indiscernible] what reaction by U.S. producers?

Not only gain I'd say, and Jay can chime in here, I don't know that U.S. producers have done much different. It seems to be that they're staying pretty disciplined. Sure, we see some movement in rig activity to different maybe producing zones or maybe different areas of their acreage that they have discretionary acreage. But other than that, I'd say they're keeping discipline.

I'd agree with Natalie. We do hear some conversations from the independents about cadence, maybe moving up where they think they can on our gathering systems. We've seen incremental growth, call it, over the last 3 months, but that could just be anecdotal.

As to the first question, in Jean Ann, a supply disruption like we have changes a lot of things. And we're seeing interest from countries to like India. But it's a funny thing. We're geographically challenged when it comes to LPG and India. And the question will be, when this is all over and everything returns to normal, do they still want to lift U.S. LPG when the AG is so close to. Right now, they're showing a lot of interest.

The second question is just on capital allocation. Randy, I appreciate your comments on the $1 billion of discretionary cash. The question is, assuming you're able to realize stronger results this year as a result of the conflict. And would you maintain that 50% to 60% allocation to buybacks versus debt pay down or if that $1 billion turned into $1.5 billion, for example, would the incremental above plan just go to buybacks since your leverage is already within the target?

Yes, Michael, I like the way you're thinking this morning. Yes, Michael, I think we would still, in the near term, -- when we think about 2026, we'd probably still maintain that 50% to 60% split. 2027 could be a different story. But I think 2026 still probably maintain that split. .

Our next question onto the line of Brandon Bingham of Scotiabank.

Just thinking about the 2 new plant announcements in the Permian, and I know it's barely -- hasn't even really been a month since the macro update. But just curious what you think the go-forward cadence should be for Permian processing capacity, I believe, Previously, you guys were around 1 or 2 a year with the thought process. Do you think we're moving more to a 2-plus environment? Or just how should we think about that moving forward?

This is Natalie, I think we're probably trending closer to 2. And obviously, that depends on how GORs shape up. But Cory, the GORs are increasing, that is definitely true. So I'd say we're turning more to 2 per year.

Okay. Great. And then maybe just shifting over to the global supply-demand dynamics, especially on the demand side. Just curious what you guys are seeing for refined products and crude and what that might mean for your export business moving forward?

Yes, Brandon, this is Jay again. Yes, we've seen volumes leave our dock. I mean you go back to first quarter last year, I think we -- for fourth quarter, we were up 70,000 barrels a day on exports. -- and then add back to the first quarter, that's another 70 with the SPR barrels, now looking for second quarter, I mean, we could be well over 1 million barrels a day.

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

I just wanted to quickly focus on Slide 17. It looks like PDH units are operating much better based on that slide. And I think you did do some kind of turnaround on the PDH unit 2, and it's been operating better after that. Can you speak to those dynamics, please?

Yes. This is [indiscernible]. PDH 2 has been running much better and much consistent lease since the turnaround that we had last year. The teams have put a lot of work and work very closely with our licensing partner, and have resolved a number of the issues that we had and looking forward to sustained operation of that unit. PDH 1 as well. we've invested a lot over the years in improving the reliability, and we still have some projects that we're working, but I think what you're seeing in PDH much improved reliability in that unit as well due to the investments that we've made over the last few years and reliability as well. And the team we've got gets working out there. And just knocking down the barriers that we've had out there over the previous years and good work by those folks out in our Belvieu PDH team.

Perfect. My quick follow-up is the macro comments you made at the beginning of the call, which were actually very informative. And you talked about 15 million barrels of total disruptions. And then straight probably normally operating maybe only in July. I'm just trying to understand what does this do to various storage levels of crude, refined products, do you think like because based on this depletion, like storage levels could probably take a year or so to get fully replenished here? If you could talk about some of those dynamics, please?

So if we look at the numbers, and then I think Jim was pretty spot on with saying around 500 million barrels a month of lost supply depending on who you ask. As you pointed out, it's somewhere between 10 million and 15 million barrels a day of lost supply through the Straight of Hormuz. That's crude oil products and -- so just take 12 million barrels, for example, multiply that times 60 days. You've lost 720 million barrels through the straight for global supply.

So imagine if we can get back to normal and let's say we're or down a handful of barrels, you're only going to get maybe 1 million or 2 million barrels above that. So it could take years to get back to where we were before the war.

What we don't know is what's been destroyed or damaged by the war and what it takes to repair that. I mean, we've heard about the train that Qatar has, but there's still not a hell of a lot of information as to what other assets have been damaged.

Next questions from the line of John Mackay of Goldman Sachs.

I just want to go back to the 2027 kind of soft guide from the last call. You talked about it a little bit earlier in this one, but I just want to put a little finer point on it. When you shared that update, were you thinking of '27 being a kind of what had at the time thought to be a kind of softer 2026 macro environment or a 2025 macro environment where we weren't going to have a lot of spreads? Or was 2027 meant to be a more kind of normalized environment, maybe closer to what you outlined in the fundamentals update a couple of weeks ago. Maybe just kind of walk us through the kind of macro behind the '27 piece.

John, this is Randy. I appreciate the question. Yes, really, what we were looking at when we saw the potential for 2027 was really just fee-based EBITDA growth. It was -- we were in a situation in 2025 and coming into 2026, Jim mentioned earlier, it was really a benign environment for commodity prices and spreads. So really, the driver was really fee-based cash flows off new assets going into service and also around the acquisition that we did from Occidental Petroleum that you'd start seeing those volumes show up on our system at the beginning of 2027. Those are really for drivers. .

I appreciate that. That's clear. And then maybe just switching to kind of the broader macro commented a couple of times on this call about the disconnect between the, let's say, paper market in the physical market. Can you talk a little bit more about that and maybe what you think is driving the divergence or what could drive a convergence in that?

Yes, this is [indiscernible]. I mean you're seeing strong physical premiums, for example, in data of Brent, but I think that we're alluding to is the forward market may not be accurately reflected in what we're seeing in the physical market. It's probably not high enough.

It may sound like you'd expect the kind of futures market to drift up over time even if we get closer to, let's say, some clear resolution in the rate.

So it sure looks like.

Our next question comes from the line of Gabe Dow of Truist.

I was hoping maybe to just touch on the gas side just for a second. Maybe Haynesville gathering -- is there in the shoulder season now and front month at 250. We'll see what happens in the summer, but curious if you're seeing any change in behavior. It does seem like privates build productive capacity to turn on at the appropriate price in. But curious if you're seeing any change in the behavior?

This is Natalie Gayden. You're right, the privates, you see some rigs or quite a few rigs actually running. And so I think we expect a little bit of pop on our system in the Haynesville at the end of the year. And otherwise, it looks pretty steady for the most part. Maybe it'd be a growth, I don't know what Corey's got in the forecast, but something like that.

All right, Natalie. And just a quick follow-up, maybe shifting back to the Permian as the commercial team tends to win some new business, obviously, a competitive basin. But just curious, what's most important to producers today? Is it reliability just given where pricing is, fees, differentiation given your story capabilities? Just trying to frame the competitive dynamics today.

Well, we always use our integrated value chain to compete. There's no doubt about that. And then cost of capital and what it takes to build out whatever a producer needs. I will say, an established footprint that far reaches into areas of the basin that people are producing in as a competitive advantage because you're already there. And when producers want to bring on gas in the next 12 months, you kind of have -- you already have a foot in the door per se. So that would be a mix of all of the things, integrated value chain and just geographical position in the basin.

I'll just add that Natalie operates a super system out there, which provides our customers a lot of reliability.

Our next question comes from the line of Julien Dumoulin-Smith of Jefferies. .

This is Rob Mosca on for Julian. On the CapEx revision and the planned FIDs, I would imagine you'd line of sight to these projects when you issued guidance last quarter? Should we interpret this to mean that incremental FIDs like a new frac could bias '26 CapEx higher? And is what you have now actually a pretty firm number? And also maybe if you could provide an update on those commercial agreements you spoke to with Exxon last quarter?

Yes. The first part of your question, no, our CapEx guide does include anticipated projects that are under development. I will talk to specifically any unannounced projects, but we do have some projects that are under development that are in that guide. Previously where we were, we had on the 2 processing plants that we just announced with the earnings release this morning, we actually had the long lead items associated with that plant in our guide. We just did not know as far as when we were going to come in and actually FID those and again, just with the volume growth we've seen in the Permian, but FID came earlier. So that was, if you would, the reason for the increase in the CapEx guide for this year because we'll see some of that CapEx happening in like the fee.

And this is [indiscernible]. On the NGL side, on the fractionation side, not only mentioned, she's probably up on the upper end of her guidance. So we're always looking at building fractionators. We like to bring on fractionators full helps the economics. We've got a lot of levers within the system. Honestly, we were probably a little late on 14, but we got a lot of levers. So we'll see if we need another fractionator. And if we do, we'll build one.

I'm not sure what your question is on the Exxon side. But on the downstream agreements, I would say that we talked about, I would say a lot of those agreements were just extensions of deals that we already had, and it was just a natural fit why we're in the conversations about Bahia to go ahead and extend those contracts.

Got it. No, that addressed it. And for my follow-up, just wondering how we should think about the quantum of that could be shipped out of NRT 2 Phase II once it's online relative to the 360,000 barrels per day refrigeration capacity. It seems like you guys might have just 1 dock there. I'm wondering how contracted that capacity is until the EHT agent comes online on the LPG side at the end of this year?

Yes, this is Tyler Cott. I'll just reiterate again that over the longer term, we're contracted around the range of 90%. We have propane contracts that will start to ramp pretty quickly at NRT. And I think as we've said before, we expect NRT to do a good amount of propane in the balance of this year, and that will transition to ethane as our EHT capacity comes online late this year.

Our next question comes from the line of A.J. O'Donnell of TPH.

I am just wondering if I could just go back to some of the comments on damaged infrastructure in the Middle East. I think we saw from Saudi Aramco this morning, they're going to be halting LPG shipments through May. There's been some published price indexes from third-party sources showing that spot loading rates in the U.S. Gulf Coast have been as high as $0.55. And I'm just wondering, given that Phase 2 of Nature River will be up soon. Curious how you would characterize that rate and what maybe you're seeing in terms of spot opportunities and how that could affect the return profile of your 2 new export projects?

Yes. We've seen elevated spot rates. They've been volatile. They've been as high as kind of what you mentioned, and they're off from those highs now. I think going back to what I said earlier, our system now has a significant amount more flexibility than it did previously. And so we'll respond to what products the markets need and have the highest value with the spot capacity that we have available.

Those products being ethylene, propylene, LPG and ethane.

Okay. Great. Then I just had 1 more on the crude business. looking at the Q1 results, I was just -- could you provide a little bit more detail on kind of the specific drivers behind the lower sales margin and lower transport revenues. Curious with the higher commodity strip and overall volatile basis spreads that you guys have been citing. Is this something that we could see kind of reverting in Q2 and the rest of the year?

Yes, A.J., this is Jay again. As Q1 results, we had a headwind with the Eagle Ford JV renegotiation on some fees there and then some mark-to-market noise. -- lower spreads. But you brought up looking forward, the spreads increasing, that really didn't take place until, call it, April business. But your point is valid. We see definitely at least as April looks now, that turning around.

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

Just wanted to come back to some of the commentary that you provided on the macro level. And just wanted to see, I guess, the industry, as you said, I don't think has really responded with a lot of new rig activity. And wondering what you think the industry would need to see in the market to pick up activity? And do you expect us to get there? .

We hear from producers is they're going to stay disciplined. Go ahead, Natalie.

I think that's true. I mean, we'll stay disciplined. We have a few companies that may break out from the back, but they're private in nature and don't add a whole lot to the bottom line. So that's what we're seeing. .

Do you see any certain price levels out there in the '27 curve that might start to warrant more activity? Or just can't tell that?

No, this is Todd. I don't think it's necessarily a specific price that was probably more focused on the back of the curve being lifted up and not just next year needs to get looked at from any year beyond that.

Got it. And then just wondering for the CapEx backlog as a whole, if you might be able to share, I guess, how much of that could be allocated to kind of projects that have not taken FID yet? Just trying to get a sense for how that might look?

For 2026, Jeremy, that's getting pretty granular there.

'27 works as well.

Probably for 2027 -- Chris, I mean, I would say probably half of 2027 is not spoken for. Somewhere between 50% and 65%.

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

I wanted to clarify on Neches River Phase I. Would you have contracted any of the LPG shipments on that since it's only an interim service until you switch to ethane? Or is that all spot? And then I just want to confirm the time line you would switch to ethane, you're required to do that at year-end?

We do have propane contracts that we'll be ramping up here at NRT on the Flex train. And then as EHC comes online, we'll satisfy that contract demand long term at EHC. Our ethane commitments are generally driven by when the VLECs arrive and largely, that's later this year and into next year.

Got it. Bigger picture question as a follow-up. What would you say is the biggest opportunity for Enterprise with the situation in the Middle East and some of the commodity dynamics? Is there any particular business or commodity that you see as most exciting that you'd call out or things we might not be thinking about? .

Frankly, I think ethane has surprised me the appetite for it. I could say that growing. And another one is we're going to ship out what, Chris, 3 million barrels of ethylene this month?

That's right, Jim. Yes, our ethylene exports over the last couple of months have been really high. .

What excites me is how we have broadened the offering across our docks. We're not just an LPG dock. We're not just a crude oil dog. We're a hydrocarbon dock. And I think I'd like to see that grow. We've got our own target to support where we like to be that I'm not going to share, but I like the broadening of the offerings rather than a specific project.

And probably the only thing I'd add to that, just really what is just the improvement in fundamentals for our petrochemical customers has really been a big change, which is good to see for them, and we'll get the benefit from just volumes going through the system, but that's much improved.

Yes, healthy petrochemical business is good for Enterprise. And they were running pretty strong before this what's changed? Some are going to heck of a lot of money.

Our next question comes from the line of Jason Gabelman of TD Cohen.

Most of my questions have been answered. I wanted to ask about another commodity exposure. You guys have around octane enhancement. I think in 2022, that business did in '23, north of $400 million of gross margin. How are those spreads looking right now? Do you see that repeating this year? .

And we just now are coming out of a turnaround on our Oleflex unit. And so we're not able to get full capacity, but if we're coming out of that, and we think it's going to be strong through the quarter. .

I would now like to turn the conference back to James Teague for closing remarks. Sir? .

Thanks, Latif, and thank you to our participants for joining us today.

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

Thank you for standing by. Welcome to Enterprise Products Partners 2026 Fundamentals Update.

[Operator Instructions]

I would now like to hand the conference over to Joe Theriac, Vice President of Finance and Investor Relations. You may begin.

Thank you. Good afternoon, and welcome to the Enterprise Products Partners conference call to discuss the company's newly released annual supply appraisal forecast. The scope of the conference call will be limited to the supply appraisal forecast. Questions with respect to our current business outlook or financial results will be deferred to and addressed during our first quarter of 2026 earnings conference call on April 28.

Our speaker today will be Corey Johnson, Senior Vice President, Fundamentals and Commodity Risk Assessment of Enterprise's General Partner. Other members of our senior management team are also in attendance for the call today. As a reminder, the information presented during this call represents the company's current views on certain key midstream energy supply and demand fundamentals and is qualified in all respects as forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

Such forward-looking statements are based on the current beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team, including forecast information published by third parties. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

And with that, I'll turn it over to Jim.

Yes. Thank you, Joe. We've got Corey Johnson here that, as Joe said, heads up our fundamentals group as well as our financial desk. And Corey has been around for a long time. He's been in virtually every business at Enterprise. And he's put a lot of work into this along with his fundamental thing. Corey?

All right. Thank you, Jim, and good afternoon, everybody, and thank you for joining us. Before we dive into the fundamentals presentation focusing on supply appraisal, I do want to touch on a few macro issues and start out with looking at U.S. production. So when we look at U.S. production in 2025, we saw that the producer was very disciplined. We expect that to continue into 2026. In addition to that, we expect the Permian Basin to be responsible for 85% of the liquid hydrocarbon growth in the United States. This is slightly down from our forecast in 2025. All of this can be found on Page 3 fundamentals outlook.

Now why are we at 85% and not 90% like we had the prior year? Well, we're actually seeing some growth in the offshore area, Gulf of Mexico, which is quite welcome to our Gulf of Mexico assets. I'm happy to see that production returning. Now moving on to global demand. Petrochemical remains the primary driver for global demand for liquid hydrocarbons. In addition to us seeing that demand continue on the petrochemical side, we expect to see those avenues become brighter as we look at the destocking as a result of the Iranian conflict creating tailwinds not only for U.S. crackers, but crackers abroad that are being supplied by U.S. producers. Low-cost feedstocks provide advantages for the U.S. petrochemical industry and also those over in Asia and in Europe.

And when we look at OPEC, OPEC typically provides market stability. In this particular case, as a result of the closure of the Strait of Hormuz, it's actually created quite a concern. A lot of the spare capacity that everybody has been talking about is capacity that you find on the wrong side of the Strait. So it was not there to help when needed. What actually ended up helping was the unexpected Russian barrels that have been sitting on the water for many, many months. OPEC production in the month of March was off by approximately 8 million barrels per day, producing around 20.8 million barrels a day of black oil. If we add in refined products and also petrochemicals and NGLs, that number is closer to 15 million barrels per day, quite the impact on the overall industry.

As we look at natural gas demand, we expect that demand to continue to be strong, driven by not only LNG, but also by AI and data centers across the United States. Now we're not too worried about natural gas prices at this time because we see U.S. production continuing to be strong and keeping our Henry Hub price below $2.70 as we see it today. Do we see slight upside to this value? Absolutely, but we do expect it to be a cost advantage feedstock as well.

Moving to the next page, Slide 4. As I mentioned before, the U.S. producer will remain disciplined. That is our expectation, and that's what we've been seeing in the market. If you look at the chart before you, from 2023 to 2024, you can see that crude prices range somewhere between $70 and $80. During that time period, producers produced somewhere around 300,000 barrels per day growth year-over-year-over-year. We expect to see that trend continue. There's no reason why we would see them step out. As you can see, the forward curve gives us a price of somewhere between $65 and $75 when we run out to 2029.

Now today, we do see some short-lived very high prices. In fact, if you look at this chart, which was constructed yesterday at around 9 in the morning, prices were about $102. Now we've seen those prices fall about $10 from there, and we're closer to $92 today. So quite a bit of volatility, which is not what producers want to see when looking deep into the future for long-term operations. Could we see a near-term change in operations, specifically cadence of drilling and fracking? Yes, but I think it's going to be limited to small privates. Integrated majors are likely to maintain the cadence that they have and continue to produce what they were expecting to produce before the conflict.

Moving to Slide 5. EPD sees the U.S. production forecast for the Lower 48 states to be slightly changed from our previous forecast, but nothing too dramatic. If we look at our oil forecast, we see that the barrels produced are going to be right around 14.4 million barrels per day in 2030. This is a 900,000 barrel per day increase over where we expect to see barrels produced in 20 -- or where we saw barrels produced in 2025 at about 13.5 million barrels per day. When we look at our wet natural gas, we expect that to be up about 1.7 Bcf a day relative to our previous forecast at around 132.5 Bcf a day in 2030 with a starting point of 118.1 Bcf a day.

Our NGLs are relatively unchanged. We're showing 9 million barrels per day in 2030. That's about 100,000 barrels less on the page that you see. But in reality, rounding brings it closer to 50,000 barrels a day. So very, very, very slight change in our NGL forecast with about 1 million barrels per day of growth from 2025. Now one thing that I did skip over, I want to set the stage on where we were on this forecast from a pricing perspective. We used $65 crude, $3.50 Henry Hub, and then we took where frac and rig counts were as of today, which is right around 480 rigs and 170 frac crews. And as we push down the time line to 2030, those crews would decrease through efficiencies. So we're pretty much taking where we see it today and trending.

Let's turn to the next slide. So when we look at the Permian Basin, I brought this slide into the deck specifically for a reminder, a reminder of how truly prolific the Permian Basin is. When we look at the 2 maps on the top portion of the slide, it shows about 55 million surface acres. If we compare that to the likes of some other large basins, for example, in Appalachia, Marcellus, Utica, 55 million acres doesn't sound all that big. But when you think about what's underneath, it's very, very impressive. On the Delaware side, you have over 15 locations or drilling locations that you can hit, as you can see in the stacked pay cross-section at the bottom of the slide. And then if we look on to the right side of that cross-section, 10 different pay zones in the Midland Basin. So take that 55 million surface acres and on average, multiply that by somewhere around 13 different opportunities. It stacks up and it creates a lot of opportunity.

Let's go to the next slide. So here's the real reason why I showed you the slide previously. It's all about locations. And so what we've done is an analysis looking at what total Permian locations look like in a $60 market. So if we look at that chart, it shows $60 with what we call a 25% rate of return. There are 80,000 locations in the Permian Basin at a $60 mark with a 25% rate of return. If I look a little bit deeper into that and break this down by producer, I can look at it and say, how many of my top 10 producers have locations at $60 with a 25% rate of return? Well, or how many locations do they have? Well, they have over 60,000 locations, bringing it to over 75% of the basin is controlled by 10 integrated producers -- or I shouldn't say integrated producers, but 10 producers.

Now it's not just 80,000 locations in reality. It's 80,000 locations at $60. If I slide that scale to the left to the right, locations will increase and decrease. For example, if I were just to say, take that number to $70, 80,000 locations goes up to almost 110,000 locations. So the basin is prolific, and it continues to provide opportunities. As we've seen recently with Diamondback's statement saying that they have recently added 900 gross locations in the Barnett 500 net to their company as they expand into new areas.

Going to the next slide. We're going to focus now on Permian production. As I mentioned before, 85% of the growth in the United States comes from the Permian. Similar to the overall 48 states, we run a bottom-up analysis, and we look at rigs, frac counts and what that cadence looks like. So starting out with rigs. Right now, we've got about 220 rigs in the basin and 78 frac crews operating. We expect those numbers to hold steady through 2026 and then start to slowly decline as we come out into the future. And again, this is a function of advanced technology and efficiencies.

One thing that we've been really looking very carefully at with Permian production and looking at a lot of our metrics is it's not so much how many wells are drilled and how many of those drilled wells are completed. It's more about how many lateral feet. Now one well that we see today is not similar to the well that we saw 3 years ago. These wells have much longer laterals with much more complicated drilling where we see a lot of multi-bench completion and laterals that are no longer 1 to 2 miles, but more like 2 to 3 miles.

So starting out with oil, where forecast for oil production in the basin is down about 100,000 barrels a day year-over-year at 7.5 million barrels per day. In 2025, our forecast was at 7.6 million barrels per day. Slight change to the down, but not a whole lot, still growing about 1 million barrels per day from a 2025 mark of 6.5 million barrels per day. If we look at wet natural gas, our wet natural gas is going to grow by about 6.7 Bcf a day to a total of 35.4 Bcf a day by 2030. This is up about 1.5 Bcf a day to our prior forecast. And then when we look at our NGLs, we expect to see 900,000 barrels per day of growth in 2030 from our 2025 mark at 3.8 million barrels per day. This is about 200,000 barrels per day over our previous forecast.

Now one very important point that I'd like to address is what is the growth rate of not only our wet gas, but also our NGLs relative to crude. In 2025, that growth rate was about 1.4x. Now we see it growing at about 1.6x as we see the gas-to-oil ratio in the basin starting to increase or should I say, continuing to increase.

Turning to the next page, Page 9. Permian Basin trends. So when we look at the stacked pays, they all continue to deliver. As I mentioned, they grow and they grow and they grow. We've had about 18,000 horizontal wells completed in 25 different named geologic zones over the last 3 years. When we look at what the producers are reaching out for, they're doing step-out drilling in places like the Barnett and the Woodford into these nontraditional benches. Today, we say that they're nontraditional, but they seem like they really are becoming more and more common every single day. A lot of that is driven by the fact that next-generation technology is making it a lot easier for producers to drill these locations as they see their economics looking better. Costs are coming down and total recoveries are going up.

What's driving this? Spacing, cube drilling, lighter proppants. All of these things, again, are helping with total recoveries and costs. Not to mention, consolidation within the basin allows people to share technology and also create more efficiencies.

Turning the page. So as I've mentioned before, 1.6x growth, wet gas and NGLs relative to crude oil versus what we saw in 2025, 1.4x growth. So obviously, that says gas-to-oil ratios are continuing to increase, and that's exactly what we see here. So I'm going to start with the top left-hand corner, the total Permian. The left-hand axis shows us what our gas-to-oil ratio is in Mcf per barrel. The right-hand side shows what our gas rate is on Mcf per day. That gas rate is a peak gas rate that we see at the early point of production. So for example, looking at 2017, peak gas rate was about 1,300 Mcf per day. The GOR at that exact moment in time was 1.91 GOR.

As we move in time to 2025, the peak gas rate is about 1,900 Mcf per day and the GOR 2.24 for the total Permian. As you can see with the arrow, it's moving from the lower left to the upper right. Gas-to-oil ratios are, in fact, increasing upon peak production. We see the similar trend in Delaware, more pronounced in New Mexico and a little bit less pronounced, but absolutely there on the Texas side as well in the Delaware Basin. When we look at Midland, interestingly enough, we don't see that trend as pronounced, it's a little bit flatter. We do see a slight growth in that number, but nothing like what I would say our teams are seeing. So if we were to ask, for example, Natalie Gayden and her team who are out talking to producers all the time and Jay Bany and his teams, they would tell us what we're seeing in the basin is the gas-to-oil ratio in Midland look a lot stronger than that.

So what do we have to do? We dug a little bit deeper. So let's take a deeper dive into that. Let's turn the page to Page 11. Looking at type curves is what gave us the answer. So year in and year out, the supply appraisal team nailed it on crude oil. We were always getting numbers exactly right on crude oil. And every single year, we were a little bit lagging on our wet gas and NGLs. I think everybody shared that same challenge. Well, we took that deeper dive when we looked at our type curves, and it's not about looking at what the type curve looks like today. It's about looking at what we think the type curve is going to look like tomorrow. And so when we projected out a trend of what those type curves will look like, the crude oil stayed relatively the same, but the natural gas type curves started to shallow.

So the chart here in front of you shows a 2025 and a 2026 type curve for a typical natural gas well in the Permian Basin. The lower light blue line is what the '25 curve looks like and the darker red line above that shows the '26 curve. The shaded blue area represents the amount of wet gas production that comes from that well. Now we've calculated it for you. If we look at this type curve over an 18-month time period for 1 well, you would receive 100 Mcf per day additional relative to what we would say the 2025 type curve well would look like. That doesn't seem like a lot, but when you multiply that times 485 new wells per month for 18 months, that number starts to add up. In fact, it reaches 365 million cubic feet a day and about 48,500 barrels per day on average of incremental NGLs simply by shallowing that curve, quite the impact.

Let's turn to the next slide. Many of you have seen this slide before. This is a simple visualization of what a barrel of energy looks like coming out of the Permian Basin. In 2022, for every barrel of crude, you get about 0.5 barrels of NGLs and 0.5 barrels of natural gas or 3 Mcf. When we look forward into the 2020 -- actually not look forward, but the 2025 barrel, as we see it, you get 1 barrel of crude oil, 0.66 barrels of NGLs and 0.64 barrels of natural gas or 3.78 Mcf.

Now one point that I want to make about this slide, and it's a very important point to producers is what is the impact of negative gas pricing in the basin. So if we look at a, call it, negative $5 number that we see today in the Permian Basin, this calculates to about a $19 liability for every single barrel of crude oil that is produced. Now when we're looking at a $90 barrel of crude oil and we back out $19, it's pretty dongle on profitable regardless.

But what does this really do? Well, if we turn the page to Slide 13, it makes the producer very excited about new pipeline capacity that is coming. Now here's where I'm trying to go on this, and I want you just to take your time and follow me. When I look at this chart and I look at the light blue line on it, that represents what we expect from a production perspective. So all the way in 2030, that light blue line reaches about 27.5 Bcf a day. That's the dry gas production that we're forecasting out of the Permian Basin. When I look at this slide, I immediately think, okay, where could we be wrong? And this is where we could be wrong, and it all depends on timing of these pipelines coming and if, in fact, the Permian to REX pipeline, which is the dotted non-FID, the pipeline that you see at the very end.

Now if I operate these pipelines as we would expect or if we operate these pipelines as we would expect, 32 Bcf a day in reality is about 30 Bcf a day of true usable operational capacity giving up and downtime throughout the course of the year. So if we operate these pipelines at 30 Bcf a day, you've got a lot of producers finding ways to make natural gas disappear because they're sitting on, as I mentioned, that negative $5 gas, so they're doing anything and everything they can, whether it's going downhole, choking back some wells or even finding ways to create electricity wherever they possibly can. These are opportunities for natural gas to come back to the market when these pipelines arrive.

So we could see about 2 to 2.5 Bcf a day fill these pipelines pretty quickly without a whole lot of crude growth because that production is already there. It's just curtailed. And what comes with 2.5 Bcf a day of gas is about 450,000 barrels a day of NGLs. So there's definitely some potential for upside, assuming that all these pipelines get built and the timing of which we are predicting.

Let's turn to the next slide. Natural gas demand outlook. We definitely think it's strong enough to keep up with production. Global gas and power demand continue to drive the growth. LNG continues to be built out. Facilities continue to operate at higher rates than expected. Data centers continue to consume more and more power as we go on. In addition to that, when we look at global demand, we must remember that the European Union's long-term goal is to replace Russian gas, and there's no better place than the United States to supply that gas.

As we look at data centers and we look at AI, continuous power is absolutely paramount. It is not something that can be toyed with. You cannot use power that comes and goes. It has to be constant. Not only does it have to be constant, but it also has to be reliable. And natural gas and coal are 2 very, very well-suited commodities to provide that resource. So we expect to see natural gas demand continue to be very strong on the back of not only data centers, AI centers, but also industrial demand because we've got a very, very cost-advantaged market relative to the rest of the world.

When we look to the charts on the top right -- excuse me, the table on the top right-hand side, it shows what we think the low and high case is for growth. If we look at domestic growth, we expect it to be somewhere between 4 and 9 Bcf a day out to 2030. And then if we add in exports, which includes pipelines to Mexico and LNG, we expect that to increase by a further 7 to 17 Bcf a day. If we add it all up, we're right around 11 to 26 Bcf a day, low case, high case for natural gas growth in demand. Now if we take the middle, that's about 18 Bcf a day. I would lean to the higher side given what has happened in recent time with the Iran conflict. So I do definitely think that the opportunities for U.S. supply reliability, I think you're going to get a little bit more demand out of the United States. It's going to be stickier.

Let's turn the page to Slide 15. Most of you have seen this slide many times before. It is a very simple slide. Every incremental barrel of energy produced in the United States must be exported. Starting out with crude oil today, we are exporting 4.5 million barrels per day. When we look at where we are going into the future, it's going to need to be about 5.5 million barrels per day. If we look at what's happening with ethane, it's almost 700,000 barrels per day as we speak, exported and that number is going to continue to grow. Natural gas, as I mentioned before, LNG is growing at a very quick pace. Today, we're at 20 Bcf a day, and it absolutely would not surprise me if we hit that 35 Bcf a day mark by 2030. And then finally, looking at LPGs, today, we're right around 2.3 million barrels per day with room to grow.

Turning to Slide 16. World is definitely ready for our growth. The appetite for LNG continues to grow, and it continues to exceed everybody's expectations. Every year, people have their doubts, yet every year, we continue to see the growth, and we continue to see the barrels consumed. EPD expects that our LPG demand will remain strong with approximately 300,000 barrels per day of annual growth. Most of this is driven by heating demand and human needs. Jim likes to call this sticky demand. This is sticky demand in non-OECD nations that have a lot of room to grow.

In addition to that, you continue to see petrochemical demand, especially given what's recently happened in the Middle East. The destocking of petrochemical feed -- sorry, the feedstocks, but the destocking of the polymers and then also the consumption of stored feedstocks is going to provide a long runway for a lot of demand to come into the future. We look at the bottom left chart, you can see post-shale revolution. On average, we've seen about a 3.4% rate of growth since 2012 to 2025. It shouldn't surprise you when you see 295,000 barrels per day of growth year-over-year. That's why we expect to see 300,000 barrels a day of growth year-over-year. That trend has been very strong, and we expect to see it continue. As Jim likes to say, price creates supply and price creates demand.

Let's look at the next page, Slide 17. Originally, this slide was really just to focus on where the supply was coming from and where it was going to, the supply and the demand. As you can see, the United States represents about 47% of the supply today to the world. Asia, a very, very large consumer of that to the extent that it's 65% of the demand.

Now here's the twist to this. This is pre-Iran conflict. This picture is. If I were to change this picture, you would see the Middle East supply section reduced by 1.2 million barrels per day. Most of that production goes to Asia. What is remaining is now about 400,000 barrels per day of production coming out of the Strait of Hormuz. Almost all of that comes from Iran. Other than 2 vessels, all of it has gone to China. The 2 vessels that didn't go to China went to India.

Let's look at Slide 18. Why is everybody lining up for U.S. supplies? Why do they want U.S. light ends? It's very simple, price. If we look at the blue lines at the bottom, that represents your ethane, natural gas and U.S. propane. If we look at all of the red lines at top, that's what they're competing against. We obviously are in the catbird seat from a supply perspective when it comes to price. International markets will always reach for the U.S. barrel first.

Let's go to the next slide. This one is quite simple. It's just a picture looking back in time to help put things into perspective. About a decade ago, the United States was exporting about 25% of the total waterborne market for LPGs. Today, we have reached almost 50% of the overall market. Most of this driven by residential market demand on the global market, but it also is being driven by a lot of growth in petrochemical demand as well. Very well diversified, and again, quite sticky demand. We expect that to continue.

Turning to the last slide, Page 20. We are looking at ethane feedstocks and ethane exports. So when we look at ethane exports, similar to the slide before, but we're just looking at the United States because the United States is the only country that's exporting ethane. There are a few movements within the European Union, but nothing really to get excited about. Nearly 100% of the ethane that hits the water is from the United States.

Now what this slide also shows us are the other molecules related to ethane that hit the water, ethylene and ethylene derivatives. If I add up all of these barrels and I put it in terms of total production in the United States, over 40% of the ethane that is produced in the United States is exported, whether it be as ethane, ethylene or pellets. Demand for U.S. petrochemicals, demand for U.S. NGLs, gas, crude oil continue to be strong, and we expect it to be a driver for the U.S. economy.

Thank you. If you have any questions. Chris?

Thank you, Corey. Operator, we're ready to open the call for questions.

[Operator Instructions] Our first question comes from the line of John Mackay with Goldman Sachs.

Look, Corey, you touched on this briefly, but I'd love to hear a couple more thoughts from you on really how much of this outlook has changed given what's happened in the Middle East over the last 1.5 months. Said differently, if we'd ask you to kind of run the same thought process around fourth quarter earnings, let's say, what would the view have been at the time? And if I can push for it, I know we're not asking too many EPD-specific questions now. But given the context of the guide you put out there for 2027, what's kind of the macro backdrop that's framed up around that?

So I'm going to tackle your first question, then I'm going to let Chris give you the response for the second. When we look at what's happened recently, obviously, we're talking about the conflict in Iran. I really don't think our forecast because we're looking out to 2030 really has changed all that much. Again, if anything is going to change in the near term, this is going to be small privates that are trying to take advantage of momentum, not the big guys.

In fact, and this is news just in not too long ago, but if you look at Diamondback's actions recently of, I think, Chris, what we said $800 million of debt that they retired in the market at what was 4% interest rate rather than putting that towards drilling, that right there tells me that pure capital discipline, and they're going to continue doing exactly what they said they were going to do. They're going to grow at a methodical rate and provide returns to their investors.

Now where things could change, and it's not necessarily a part of our forecast, but it's definitely something that Enterprise pays attention to is NGL demand overall, and I say NGL because it's not just LPGs, it's ethane, it's propane, it's butane, it's naphtha. This demand is going to be stronger for longer, in my opinion, really because of the supply constraints that we have seen over the last, call it, 40, 50 days. And we're probably going to see some of those markets open up maybe in the next month or 2 months. If you can tell me, I'm excited to hear. But the longer this goes on, the longer that runway gets for people replenishing things that basically are consumed or destocked.

Yes. And John, this is Chris. I think with respect to your question about how this plays into our outlook for the remainder of 2026, our forecast for 2027, I think we'll address that certainly a great question, but we'll certainly address that as we -- in 2 weeks when we have our first quarter earnings call.

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

Corey, on your point about the 2.5 Bcf per day of gas currently curtailed or choked back given the lack of residue egress. As we get multiple egress expansions later this year, illustrated in your chart, how quickly would you expect this 2.5 Bcf per day of gas to come to market along with the 450,000 barrels per day of NGLs?

So thanks for the question, Theresa. And let me -- I want to reframe that real quickly. What I was mentioning about the 2 Bcf a day, that is incremental. So that was where we could be wrong. So what I was referring to is 27.5 Bcf a day is what we're forecasting in 2030. If we look at the pipeline capacity in 2030, we have non-FID right around 30 Bcf a day of takeaway capacity, about 32 Bcf a day, if you include FID 30 Bcf a day. And if you include the non-FID, you would have about 32 Bcf a day.

So let's assume that Permian Direct gets built, which is that last one, that would give us about 30 Bcf a day of operating capacity in my opinion. Again, you've got nameplate capacity on the pipeline. You've got true operating capacity of all of these pipelines. And I'm obviously going to handicap it by a little bit. The 2.5 Bcf a day that I spoke of is basically the increase that we could potentially see of gas coming to market when these pipelines come on and the timing of which they come on as a result of gas that's truly being held back in the market today.

So as our inventory continues to grow, crude oil or supplies continue to grow and the natural gas that gets held back continues to either maintain or grow, some of that gas that could fill these pipelines is gas that's just in waiting today. Does that make sense?

Yes. Thank you for clarifying.

And then yes, 450,000 barrels a day -- or should I say, 400,000 to 450,000 barrels per day of NGLs would come with that incremental. So our supply forecast, where we could be wrong, you could see that 27 Bcf a day go up by 200 -- 2.5 Bcf a day. And then again, our NGL forecast would also go up by about 450,000 barrels per day if all of this were to come to fruition. If you were to ask Natalie or ask Tug what they're seeing in the markets, I would definitely think that these pipelines could fill.

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

I want to go back to the question on U.S. LPG demand. I guess the question is, do you expect there's going to be any kind of fundamental shift in demand for U.S. LPGs in light of the Middle East conflict? And is that already reflected in your forecast? Or if not, is your expectation that once this conflict ends and the straight is open, do you think buyers kind of go back to their prior buying patterns?

I think it really kind of focuses around security of supply. And it's a great opportunity for people to get out and procure barrels with long-term contracts and secure supplies. Obviously, the U.S. market is a little bit sturdier than other locations.

Our next question comes from the line of Julien Dumoulin-Smith with Jefferies.

Maybe to follow up on that last question a little bit more. Can you talk about the ethane forecast? I mean obviously increased pretty meaningfully here as a function of higher NGL volumes. How are you thinking about the strategic opportunity at hand for you all in as much as implicitly, it seems to be a little bit more of an export opportunity. How do you think about tapping into that as you guys talk about that imbalance, to use the term here globally? How do you think about the various facets that you guys could pivot to it?

Obviously, we're continuing to expand our ethane export opportunities, and there's some growth that we do see in petrochemical complexes in the United States that's going to happen. So there's new demand coming domestically. And as we already mentioned, we've got some opportunities to export some ethane in the future beyond what we're doing today.

Fair enough. And I mean could you speak a little bit more to the technology and efficiency? You talked about this analysis underestimating some of the changes year-over-year here. What's driving some of that, if you can speak to that a little bit more fundamentally, right? And as much as the production outlook clearly seems to be trending in a certain direction here?

Yes. I think Exxon has spoken pretty extensively about the lighter proppant. If you look at Diamondback. They're very good at multi-bench completion with their acquisition of Endeavor. Endeavor was, in our opinion, one of the better drillers in the basin, and they picked up a very, very good operator and driller, which just only enhanced everything.

Our next question comes from the line of AJ O'Donnell with TPH.

I appreciate all the details. Just wanted to go back to maybe some of these nontraditional benches in the Permian that you've talked about producers stepping into. Curious, as you think about the infrastructure that's already in place or what needs to be in place, like how early are those conversations? Are we potentially going to see an acceleration there? Just curious how that all kind of plays into EPD's overall asset footprint.

Well, I think strategically, we're located pretty nicely when you look at Midland Basin and also into the Delaware Basin. Some of these step-out plays, well, we're still looking at type curves because they're very young, but it does appear that they're a little bit gassier than other type curves, which is going to play very nicely into the Enterprise book.

Okay. Just maybe one point of clarification there. I mean is that additional like investment that would be needed on EPD side to account for this growth? Or do you feel like you have the infrastructure in place there?

Yes, AJ, this is Chris. I think we've been adding additional processing plants in both sides of the basin year-over-year. And I don't think that, that trend is going to end anytime soon. As Corey alluded to in his production outlook that the basin has a lot of drilling locations left that are highly profitable. So we do think we'll continue to add and build new assets and grow alongside that production growth as our customers are asking us to build those facilities.

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

Just wanted to go back to the type curves and the changes year-over-year. Just wanted to make sure I understood quickly that, that is more of a basin average change, not necessarily indicative of specific benches? And then just any thoughts on looking at this production uplift maybe in a different way, how many fewer wells would you say might be needed to reach these growth numbers at this point as a result of the flatter declines moving forward?

Well, that's a really technical question. I definitely need to get a calculator out for some of that. When we look at that type curve, yes, that's a generalist type curve for what we're seeing with newer production. So we're projecting these type curves to go forward into the future. Some of this is us looking at production that we see on our system and then also production that we see through other service providers as well where we're seeing that shallowing of the curve, and we continue to see it shallow more and more and more. So again, this is a projection into the future of what we think that type curve is going to look like.

As it pertains to how many of these we're going to produce, I mean one of the challenges, if we look at it from a completion perspective or a well-by-well perspective, it's kind of difficult to use that calculation on a go-forward basis. Brandon, who heads up our supply appraisal team, what he's really trying to condition all of us to is looking more on a lateral foot basis rather than on a per well basis because these wells are changing pretty drastically relative to what we've seen in the past. So one well does not equal what -- a well in the past doesn't equal what one well equals today, especially when we're seeing wells that are reaching beyond 3 miles.

Our next question comes from the line of Jeremy Tonet with JPMorgan Securities.

Just wanted to compare, I guess, your expectations for LPG, NGL export versus existing capacity as you see it today on the Gulf Coast. Do you see sufficient capacity today with known expansions? Or do you think that the industry needs to expand further based on the growth trajectory as you outlined there?

Yes. This is Tug Hanley speaking. We believe there's sufficient export capacity currently available for quite some time.

And that's both ethane and LPGs? Is it similar for both?

Certainly, for LPG. Ethane, that remains to be seen.

Got it. And then I guess, same question on crude oil export side.

That's more of a function of freight, but there's certainly sufficient capacity to export the crude oil, but certain docks can export it more efficiently than others.

Got it. And just curious, I guess, with the imbalance in LPGs, as you outlined there, and just the gap in the market as it relates to display or Middle East LPGs that won't be supplied, do you think that the -- there could be sufficient, I guess, incentive to produce more in North America, be it in kind of other formations outside of the Permian where the economics might be dictated more by NGLs in a combo play than the Permian where it's almost associated NGLs, if you will?

I mean I guess you're relating to Argentina?

I was thinking the Mid-Con, but I guess you could go anywhere you want.

I mean I definitely think that the challenges we've seen in the Middle East provides an opportunity for not only the U.S. producer, but the midstreamer to capitalize on secure supply out of the United States.

But to your question on Mid-Con, what's the economics for a producer on what percent is oil-based?

I mean not a lot of it. I mean if you're going to -- it's all -- of it is oil-based. Right. So if I'm going to drill, I'm going to drill in Permian.

LPG is not driving the economics.

Not at all. It's crude oil.

Got it. Okay. I didn't know if it changed the balance of any combo play outside the Permian, but understood.

Our next question comes from the line of Sunil Sibal with Seaport Global.

I just wanted to clarify something on Slide 7, where you have the Permian remaining locations with the sensitivity to crude price. So on the right side chart is for top 10 operators. Is it fair to assume that those -- that's essentially all of them or most of them are in the public domain? And as a result, you're saying that about 80% to 85% of the producers will exhibit a certain kind of a characteristic with regard to how much of the -- how do they react to the commodity prices?

Yes. There may be 1 or 2 privates in there, but it's mostly publics in the top 10.

Okay. So then just to build on that. So I think you talked about how the producers have been fairly disciplined despite the increase in commodity prices. So what we should expect is that 15% to 20% of the production, which is in the hands of privates maybe exhibit more sensitivity to the commodity prices versus the remainder of the basin. Is that kind of a fair way to think about it?

Yes, you're reading the chart correctly.

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

I just want to talk a little bit about the macro trend. I think globally, ethylene producers are realizing that the better way to make plastics is through the ethane feed. We're actually seeing some of the global capacity that was purely dependent on naphtha looking to close down even before the crisis started. So do you see this macro trend playing out and globally more ethylene crackers actually moving to a flex mode and basically going from naphtha towards ethane? And would that be a helpful tailwind for Enterprise in the future, basically, global naphtha cracking shifting more to ethane side?

Yes, this is Tug. We have seen a shift of naphtha crackers moving towards lighter feedstocks, specifically ethane. But generally speaking, it's also a good strong pull for our ethylene export facility as well.

Thank you. Ladies and gentlemen, I'm showing no further questions in the queue. I would now like to turn the call back over to Joe for closing remarks.

Thank you. That concludes our remarks for today. Thank you to everyone for your participation, and have a great day.

Ladies and gentlemen, that concludes today's conference call. You may now disconnect.

Good day, and thank you for standing by. Welcome to the Fourth Quarter 2025 Enterprise Products Partners L.P. Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Libby Strait, Vice President of Investor Relations. Please go ahead.

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

Thank you, Libby. The headline for the fourth quarter is a record $2.7 billion of EBITDA, surpassing the previous record of $2.6 billion set in the fourth quarter of 2024. We brought on a number of assets in 2025. Frac 14 in mid-October, Mentone West and Orion midyear, several gathering and treating projects in the Permian, the Neches River Terminal, ethane export train midyear, midyear start-up of diluent exports to Canada and finally, Bahia NGL pipeline in December. All these assets performed well, but they also filled holes created by a decline in our commodity-sensitive businesses and marketing spreads. The market realities shaped the year. Crude oil prices averaged about $12 a barrel lower than in 2024. That reduced many of the pricing spreads we benefited from over the prior 3 years.

[indiscernible] margins were weaker in 2025. A large 10-year LPG export contract originally signed at double-digit fees was recontracted at market rates. RGP/PGP spreads were $0.14 a pound in the fourth quarter of 2024, but only $0.03 a pound in the fourth quarter of 2025, which is an extension -- a reflection of the weakness in the housing market. During '24 and '25, we renegotiated our RGP purchase agreements to a fixed fee structure, which makes our splitter business largely spread agnostic. The splitters are now essentially in a note. We're fully contracted on our ethane export terminals and all 20 processing trains that we have -- we will have online in the Permian by year-end. For ethane exports, typically ships must be built and receiving terminals constructed to ultimately ramp to full utilization in our docks.

With that being said, however, the ships seem to be coming earlier than the receiving. For processing, while production growth builds over time, the 2 trains we brought on in midyear 2025 are virtually full today. Our LPG exports are highly contracted through the end of this decade, and we continue to see strong interest for additional long-term commitments. We expect modest growth in 2026 as these assets and the assets we're bringing on in 2026 continue to ramp. We expect to see double-digit growth in 2027 once these assets reach full utilization. Naysayers doubted Bahia in the beginning, but that is to be expected when you are first. Bahia and Shin Oak is an integrated system, has 1.2 million barrels a day of capacity and are running at 80%. Having Exxon as a UJI partner and agreeing to expand Bahia to 1 million barrels per day is a win for both Enterprise and Exxon.

Associated with the UJI are a dozen downstream agreements. On the export front, Enterprise continues to expand its NGL export franchise. In 2025, we loaded between 350 million and 360 million barrels across 744 ships, and that will only grow as we complete Phase 2 of the Neches River terminal and the LPG expansion of the Houston Ship Channel. By next year, we expect to be exporting near 1.5 million barrels a day of NGLs or 550 million on an annual. Little history lesson. We've been doing international business since 1983 when we built our LPG import terminal. In 1999, we expanded the facility to include export capabilities. Many of our customers have been with us for more than 20 years. They know us. They know how we behave. They like how we operate. They are more than just customers.

Relationships like that tend to be very sticky. We spend a lot of time with our customers around the world and domestically. For example, over the holidays, I was in Thailand meeting with 3 large petrochemical companies Chris D'Anna was in Europe in the fourth quarter, and he'll be back in March. On the crude team, Carrie Weaver was in Asia in October, and Jay Bany will be in Europe later this month. NGLs, god bless Tyler Cott and his travels, Tyler was in Asia in November with stops in Korea and India, and will be in Europe this month and then back to Asia in March.

Finally, Tug and I will be in Japan next month to visit several export customers. We're equally focused on our domestic customers, be they producers, petrochemicals, refiners, traders or wholesale. We deliver roughly 25 million barrels a month of ethane to U.S. crackers. That's around 300 million barrels a year. In total, we move over 14 million barrels per day of oil equivalent to our 50,000-mile pipeline network. Additionally, Enterprise looks at its storage hubs as a critical part of its infrastructure to support its customers.

Cushing, Midland, Houston and Mont Belvieu. These are all open access systems where our customers can trade freely without any concern of being held hostage. We are proud of our record $2.7 billion of EBITDA in the fourth quarter. But as investors look to the future, I would encourage you to look beyond the numbers. Enterprise's long-term success is driven by our culture, our teamwork, our creativity and our laser focus on customer relationships. Those intangibles are what give rise to the numbers you see each quarter. Randy?

Thank you, Jim. Good morning, everyone. Starting with the income statement items. Net income attributable to common unitholders was $1.6 billion or $0.75 per common unit on a fully diluted basis for the fourth quarter of 2025. In the fourth quarter, our adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital grew 5% to $2.4 billion. This strong finish propelled us to a record $8.7 billion in adjusted cash flow from operations for the full year 2025. We declared a distribution of $0.55 per common unit for the fourth quarter of 2025, which is a 2.8% increase over the distribution declared for the fourth quarter of 2024. The distribution will be paid on February 13 to common unitholders of record as of the close of business on January 30.

The partnership repurchased approximately $50 million of its common units in the fourth quarter, bringing total repurchases in 2025 to approximately $300 million. Inclusive of these purchases, the partnership has utilized approximately 29% of its authorized $5 billion buyback program. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 4.7 million common units on the open market for $150 million in 2025. This includes 1.2 million common units purchased on the open market for $37 million during the fourth quarter of 2025. For 2025, Enterprise will have returned $5 billion of capital to our equity investors, comprised of approximately $4.7 billion or 94% in distributions to limited partners and $300 million through buybacks, resulting in a payout ratio of adjusted cash flow from operations of 58%.

Since our 1998 IPO, we have prioritized unitholder value by responsibly returning nearly $62 billion through distributions and buybacks, all while building one of the largest energy infrastructure networks in North America. Total capital investments were $1.3 billion in the fourth quarter of 2025, which included $1 billion for growth capital projects and $203 million of sustaining capital expenditures. For 2025, organic growth capital investments were $4.4 billion with about $100 million of expenditures slipping into 2026. We also had $620 million of sustaining capital expenditures. With the completion of major projects such as the Bahia natural gas liquid pipeline and the first phase of the Neches River terminal, we continue to believe our organic growth capital expenditures in the near term will return to our mid-cycle range. With that said, our commercial teams have had great success in completing major agreements with producers since our last earnings call.

In November, we announced ExxonMobil's acquisition of an undivided joint interest in Bahia Natural Gas Liquid Pipeline and the related expansion of Bahia to 1 million barrels a day and a 92-mile extension to connect Exxon's Cowboy processing complex as well as enterprise plants in the Delaware Basin. In January, we executed agreements to provide a large producer in the Delaware Basin with integrated services, including acid gas gathering and treating, natural gas processing and NGL transportation and fractionation services. These long-term agreement supports our building a 24-inch trunk line to extend the partnership's acid gas gathering system in Northern Lea County, a fifth treater at our Dark Horse facility and a third acid gas injection well.

In addition, we executed long-term agreements with Haynesville producers to an extension of our Haynesville natural gas gathering system, along with downstream agreements to provide natural gas processing, treating and transportation services on the Acadian system. We have also had success in executing agreements with petrochemical customers that support incremental extensions of our ethane, ethylene and propylene pipeline systems. As a result of these successes and visibility to potential projects, we expect growth capital expenditures for 2026 to be in the range of $2.5 billion to $2.9 billion, netting to $1.9 billion to $2.3 billion after applying approximately $600 million in proceeds from asset sales already received earlier this year, which represents the final installment from Exxon on the Bahia sale.

The pace of some of these expenditures will depend on the cadence of producer activity. However, we believe we will be at the higher end of this range. Sustaining capital expenditures are expected to be approximately $580 million in 2026, which includes approximately $80 million for the turnaround of our octane enhancement facility that should be completed later this month. As Jim noted earlier, we expect modest adjusted EBITDA and cash flow growth in 2026 as assets completed in 2025 ramp in volume and as assets that are completed throughout 2026 begin operations. We expect this to ultimately lead to 10% area growth in adjusted EBITDA and cash flow in 2027 compared to 2026. Enterprise's adjusted cash flow for 2025 was $3.1 billion. And this adjusted free cash flow, that's our cash flow from operations less capital investments and acquisitions. Subtracting distributions to limited partners results in 2025 discretionary free cash flow of a negative $1.6 billion.

Based on our currently expected lower level of net capital investments in 2026, which is comprised of capital expenditures plus acquisitions less proceeds from asset sales and the net increase in distributions, we expect discretionary free cash flow has the potential to be in the $1 billion area in 2026. In terms of allocation of capital, we see cash distributions to partners growing commensurate with operational distributable cash flow per unit growth. In the near term, we expect for our discretionary free cash flow to be split between buybacks and retiring debt. In 2026, we currently expect this split would be approximately 50% to 60% in buybacks. Future growth in cash distributions to partners can also be further enhanced by the percent of common units we retire through buybacks.

Our total debt principal outstanding was $34.7 billion as of December 31, 2025. Assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio is approximately 17 years. Our weighted average cost of debt was 4.7% and approximately 98% of our debt was fixed rate. At December 31, our consolidated liquidity was approximately $5.2 billion, including availability under our credit facilities and unrestricted cash. Adjusted EBITDA increased 4% to $2.7 billion for the fourth quarter compared to $2.6 billion for the fourth quarter of 2024. Adjusted EBITDA for 2025 reached a record high, just shy of the $10 billion mark. We ended the year with a consolidated leverage ratio of 3.3x on a net basis after adjusting for -- adjusting debt for the partial equity content of our hybrid debt and reduced by the partnership's unrestricted cash on hand.

Our current leverage ratio reflects significant investment in large-scale projects that we recently brought into service and the midstream asset acquisition from Occidental, where the debt is on the balance sheet, but the result in annual adjusted EBITDA generation from these investments has yet to flow into our trailing 12-month EBITDA figures. Our leverage target remains 3x plus or minus 0.25 turn or 2.75x to 3.25x. We believe our leverage will return to within our target range by the end of 2026 when we have a full year of adjusted EBITDA from some of these projects. With that, Libby, we can open it up for questions.

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

[Operator Instructions] Our first question comes from the line of Spiro Dounis from Citi.

I wanted to start with the '26 and '27 outlook comments. So you exited '25 really strong. I was just wondering, can you guys maybe walk us through some of the puts and takes of this fourth quarter exit rate as you think about '26 growth? Just trying to get a sense of what's ratable here and if you guys see yourself still landing in that 3% to 5% growth range. And on '27, you mentioned double-digit growth. Just curious how you're thinking about the risk to achieving that level of growth. Maybe another way of asking what commodity environment underwrites that level?

I think -- Spiro, this is Jim. I think given that in my script, I mentioned, we didn't have as many outsized spreads as we had the 3 previous years. So I think this -- I think fourth quarter is weighted more ratable than not.

Spiro, just as a follow-up on the second part of your question, I think probably, as we mentioned, we're sort of looking at modest cash flow and EBITDA growth in 2026 compared to 2025. So probably at the lower end of that 3% to 5% range.

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

On your comments related to the NGL export cadence, specifically on the phases of Neches River ramping up over time. Can you expand on the cadence and ramp-up of earnings contribution from these expansions? How should we think about the ramp in steady-state contribution as we move through 2026 and into 2027?

Theresa, this is Tyler Cott. I'll speak to the volume, which should correlate to the earnings. So Neches River came online last year, as you know, the fourth quarter, we started to ramp volumes of ethane in earnest. That ramp will continue into the first several months of this year. I would say by the second quarter, our overall ethane export capacity should be very near full utilization, at which time our second train in Neches River will come online, and that will have a ramp-up profile over the next several months, largely propane at first, but then shifting to mostly ethane by around the end of next year.

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

I wanted to ask, as you know, Waha prices have been pretty volatile the last few months. Fourth quarter prices is really low, spreads were wide. Then, of course, in January, we've had this winter storm. So Waha prices spiked. So I wonder if you could just remind us how EPD is impacted by changes in Waha prices in both directions.

Yes. This is Tug speaking. So as far as a low Waha price, we have gas transport capacity. So we benefit from a higher, we call it West to East or West to South spreads. We'll be able to monetize that. And with respect to recent volatility on a higher gas price, we do have storage assets that can monetize that as well. So we benefit from volatility on both sides.

Great. And then I'm wondering if you can just give us a little color on what your producer customers are telling you in terms of their plans for 2026 and how you see that translating into supply growth, especially in the Permian.

This is Natalie Gayden. On the G&P side, our Midland volumes are outperforming the expectations, tracking pretty closely with last year's volume growth. So just to give you some color, well connects are at a record high this year of 590. And then in the Delaware, same kind of thing, the growth curve is steepening there, and we've got an estimated 500 wells turning to production this year and more next year. So we're definitely keeping our running shoes on.

Our next question comes from the line of Jean Ann Salisbury from Bank of America.

I don't think you have a ton of exposure to the E&Ps announced in the merger yesterday. But just as a more high-level, I guess, theoretical question, can you give your thoughts of how much more negotiating power a large E&P would have over midstream contracts versus 2 small E&Ps? And if there is more consolidation, if that is kind of a negative for midstream?

Jean Ann, this is Jim. With the people we have, I don't think it makes a difference. Our folks are pretty good at seeing value and doing win-win deals with producers, whether they be large majors or large independents.

Okay. Very clear. And then...

Did you expect any other answer, Jean Ann?

No, not really, not really. But I appreciate it. And I guess as a follow-up, do most of the Midland to ECHO crude pipeline contracts roll off in 2028, 2029? I know that there have been some discussion of blending and extending. So not sure if that should kind of be later at this point.

Jean Ann, this is Jay Bany. So for '28, we have our first contracts roll off. But over really the course of last year and the year prior, we have done not only new contracts to fill that space, but blend and extend. So it's roughly about 20%. You'll see roll off in '28, but we'll be working on that this year and next.

Our next question comes from the line of Jeremy Tonet from JPMorgan Securities LLC.

Appreciate the color on the 10% EBITDA step up '25 into '27 there. Just want to dive in a little bit more with regards to buybacks and the pace thereof. Is there any kind of formula that you think about or other methodology when you think about the buybacks? I think I recall if there's $1 billion of free cash flow, it might be 50% to 60% deployed towards buybacks. And so just kind of trying to figure out how that might work out over the course of the year.

Yes, Jeremy, in the prepared remarks, I pretty much -- based on where we currently are when we see 2026, with free cash flow in the neighborhood of $1 billion. We really see that split where 55% to 60% of the buyback would be -- or 55% to 60% of the cash flow would be allocated towards the buybacks. And that would really be -- it would be some level of opportunistic and some level of programmatic purchases is the way we're currently thinking about it.

Got it. And maybe if I could just pick up on the freeze-offs one more time. I wouldn't expect it to be the same type of uplift as Uri as we saw in the past. But could we see the potential for sizable uplift as optimization opportunities might have been greater than what you typically see?

Yes, this is Tug. I'll just say we saw production fall off similar to prior winter events, and we're able to more than make it up by optimizing our system. But Uri was, I would say, an exception to every winter storm. So I would not be expecting that.

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

Jim, you spent a while talking through your kind of international customer base on the NGL side. Can you share a little bit more color for us on what you're hearing in terms of demand trends and maybe how that compares to this time last year?

I'm going to let Tyler take it.

John, this is Tyler Cott. I would say, overall, obviously, there's been a lot of noise in the last several months in the international and export markets, but demand has proven to be pretty resilient. U.S. LPG is finding its way into new markets, India, Southeast Asia, other places in Asia. So demand has been pretty healthy and maybe the ultimate barometer for us is we still have a lot of interest in our export capacity long term, both LPG and ethane.

Got it. And maybe just following up quickly, maybe just to clarify what Spiro asked. It sounds like some of the ramp on the new projects that came into service last year and this year is going to pick up more in '27, I guess. But can you just walk us through, I guess, any incremental tailwinds -- sorry, headwinds you're expecting for '26 versus '25 that might offset some of that ramp?

Zach, let me take the first shot at it, Zach. 14 is full. The 2 processing plants are virtually full will be the ethane terminal you all talked about would be full at the end of the year. And LPG is full, isn't it? And the expansion, you're well on your way, the contracting that comes on in the fourth quarter.

Yes.

Did that answer it, Zach?

I think you did. Headwinds...

Commodity environment -- I'll just tell you on the LPG contract well in a way, we're 85% to 90% contracted on that.

Even on the expansion.

Even on the expansion -- that thing we're fully confident.

Headwinds are -- I don't know, $40 crude is a headwind.

The one other, I guess, commodity sensitive business that we have is our octane enhancement business, but that's only 20,000 barrels a day. But it seems like there was a big change from '24 to 2025. But really from '25 to '26, you don't see nearly that magnitude of change. So I wouldn't look for too much of a headwind there.

No, I don't think there is at all.

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

First, congrats on the beat and a strong quarter. Second, we look at your partnership with Exxon in a very optimistic way, 2 giants coming together. And I'm trying to understand, are there more opportunities to collaborate with Exxon. They're obviously looking to get big into power generation with the carbon capture and sequestration, and you have the infrastructure to move carbon dioxide. So can you talk a little bit more about your partnership with Exxon? And can it grow over time? And what are the opportunities over there?

We touch Exxon in so many places, I can't count it, and we will continue to try to do more deals with Exxon. We like them. I don't think carbon capture will be in the portfolio.

Our next question comes from the line of Jason Gabelman from TD Cowen.

I noticed in the press release, there was mention of sour gas treating capacity expansion and then potential opportunity to expand activity on the acquisition from Oxy. And the question is really, does that kind of support you filling up your Y-grade pipelines out of the Permian Basin to get over the 60% utilization on the Bahia pipeline? Or does that present upside to that number?

First of all, we said we were at 80% utilization. So we're pretty close to getting to the 600 million as we speak -- or the 1.2 million as we speak. And Natalie, do you want to speak to -- any other?

I would just say that our G&P footprint is a stronghold on feeding the downstream pipeline. So any gas that we go win or packages of gas that we bring through the gathering and processing system are good for that. So yes, an expansion of Pinon and Oxyrock volumes are eventually coming in a big way in 2027 to us is good for the NGL portfolio.

Got it. And sorry for misspeaking on that number. My follow-up, if I could ask another, is just on the opportunity on the propane side on your product pipelines in the first quarter of the year, given the cold weather in the Northeast. Can you just talk about what you're seeing in that system moving propane up the product pipelines?

Yes, Jason, I'd say all of our propane pipelines saw really strong demand ramping towards the end of the year, and January has been as strong as strong as January of 2025, if not stronger.

Our next question comes from the line of A.J. O'Donnell from Tudor, Pickering, Holt & Company.

I wanted to start on the natural gas segment. It looks like Q4 results saw a decent benefit from gas marketing there. I wanted to -- if you could talk about your intentions on how to manage that marketing space going forward, particularly in the back half of the year and into 2027 as we start to see dips around Waha narrow significantly.

Yes. This is Tug. With respect to that space, we do have an open position on our natural gas capacity. As far as managing that space long term, if there's an opportunity to bundle with the GMP deal, provide an integrated solution for one of our customers, we'll evaluate that and contract that out long term. And in the short term, we'll monetize that with any short-term opportunity or volatility. And I'll pass it to Natalie.

I don't have too much to add other than -- remember, our Midland contracts are basically top with few floors. So as that gas price strengthens, which has been kind of supported, I guess you'll see the 4 Bcf or 4.5 Bcf that's coming online this year and a stronger Waha basis, we'll get the benefit of that, too. We have -- as Tug mentioned, any time we try to pair the rest of the position that we -- sorry, the capacity that we can sell, it's always paired with G&P.

Okay. One more, if I can sneak it in, just a clarifying question on this Haynesville, Acadian expansion. Curious if you could just provide some more detail behind the project, like anything about the size. Also curious like what type of customer is really driving that expansion? Are these coming from public or private producers?

This is Natalie Gayden. That's an expansion of the gathering system. So increasing treating and our reach, I guess you could say, it's a mix of privates and publics.

Our next question comes from the line of Julien Dumoulin-Smith from Jefferies.

Nice to be here. Maybe to follow up a little bit on the '27 conversation. Just to talk to the texture of the '27 CapEx guidance. You had a few projects announcements this morning. Can you speak to how much of that initial FY '27 CapEx is spoken for? Would new incremental project announcements represent incremental CapEx on that FY '27 range of $2 billion to $2.5 billion by chance? And I've got a follow-up.

Yes. This is Randy. The range that we threw out up to $2.9 billion, those are some -- that includes some projects that we've got eyes on that we've not FID-ed and not announced. So I think we've got some leeway to fill up that $2.9 billion. But again, as you've heard on the call, with some of the growth that we were seeing, we're expecting to be at the top end of that range. for 2026. And for 2027, I think we're still in that range of $2 billion to $2.5 billion.

Right. Exactly. Excellent. And just clarifying '27 real quickly in terms of the EBITDA guidance itself, you're saying you expect double-digit growth here, '26 versus '27, just to clarify here. And just what are the -- go for it.

Yes. Thank you for that. Yes, the clarification is our current expectation is that we would see EBITDA growth in the neighborhood of 10% 2027 over 2026. And again, from 2025 to 2026, really just modest growth. And probably one other thing I would clarify from an earlier question with Spiro, I think what Jim said, a lot of -- there's a lot of ratability in our fourth quarter earnings just from a business standpoint. But I will remind you, fourth quarter and first quarter are seasonally stronger businesses. So don't straight line this.

Right. Absolutely. And then just speaking of expansions, on Bahia real quickly with the UJI with Exxon. Can you talk a little bit about the opportunities there, especially as you think about volumes ultimately landing in the Mont Belvieu complex here? I mean just where could that go next as you think forward the next steps here, potentially incremental '27 CapEx or onwards?

Yes. This is Justin Kleider. Yes, so we're off on the expansion as backed by Exxon. It is a UJI. So Exxon has rights to make connections on the origin and destination front as they see fit. As Jim also alluded to, we executed 12 downstream agreements that speaks to the overall breadth of our relationship with Exxon. So it was a good transaction for Bahia, and I think it brings Exxon Enterprise closer together, and we'll see where it goes from there.

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

I want to revisit the 2027 commentary as well, if I can, Randy. 10% growth would be over $1 billion of EBITDA growth in just 1 year. I was looking back, that would be the fastest organic growth for the company really this decade. It sounds like a lot of that is from the LPG expansion and Neches River. But is there anything else you would highlight that's big and chunky, particularly in '27? And then separately, I just want to make sure, Bahia, as it's a UJI, that's treated on a net basis, right? So that's not consolidated in your EBITDA or anything like that?

I'll tell you what, why don't we handle your last question first. Daniel, do you want to take that?

Yes, UJI will be proportionately consolidated. So we will only report our share of that investment.

Yes. And then Keith, back on your earlier question, really, I would say, across the board, I mean, if you start with our NGL segment, you'll have -- we've got another plant that will be coming up -- processing plant that will be coming up in the Delaware in -- later in the first quarter. So you'll get a full year of benefit there. There's another processing plant that we're looking to bring on in the Midland Basin at the end of this year that you would get the full year benefit from in 2027.

With the Oxyrock acquisition that we made, you'll see more benefit from it in 2027. And then really then all the -- if you think about then all the downstream that comes with that, and I'll go back, Trigger 4, you would get a full benefit -- full year benefit of Trigger 4. Trigger 5, you will come in and get benefit from there as well as the incremental expansions on the asset gas. And then just think about all of that flowing downstream through Bahia pipeline into the fractionators and then into the distribution system and across the marine terminals.

Yes. This is Tug. I'll add as well, we have a lot of higher fees kicking on our Acadian Haynesville system as well.

That's helpful color. I had a quick follow-up on the NGL marketing. So a very strong quarter in Q4. You almost matched a year ago when you had those very wide export arbs. What types of activities are driving strong NGL marketing in Q4? And what are your expectations for '26? Do you see that as an area of upside?

We had -- this is Tug. We had a lot of storage opportunities. We had high utilization on our ethane export assets. Just would be a mixed bag of standard opportunities that they present themselves, we always capture.

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

Just one quick one here, and it might be a little early, but I'll take a shot either way. Just thinking back to that Oxy gathering deal, do you see any potential for more of the same types of deals on the horizon given this recent M&A news in the upstream side? Or do you kind of see inorganic spend as maybe lower priority now given the expected macro outlook this year?

This is Jim. I don't see as many girls on the dance floor as there used to be.

Thank you. At this time, I would now like to turn the conference back over to Libby Strait for closing remarks.

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

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

Thank you for standing by, and welcome to Enterprise Products Partners L.P.'s Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to the Enterprise Products Partners conference call to discuss third quarter 2025 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise's General Partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today.

During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

And with that, I'll turn it over to Jim.

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

Jim, I really appreciate those kind words and all you all here around the table. I really appreciate you all. People on the call, the analyst community, our producers, our customers around the world. I'm forever grateful for the interest and respect that you've always shown for in our fundamentals and our supply appraisal work sincerely.

Jim, I want to thank you for years ago when we sat down at your table, recognizing early on that we had something that we now know is the shale revolution. And as you put it, you had a bunch of reports on the table in front of you, and you told me something is different this time and given me the chance to establish a Fundamentals team that I've been so honored and frankly, humbled to be part of, and I really mean that.

I guess last but not least, Corey Johnson, the Data Science team that what you all have taught me over the last 4 years, I'll take with me the rest of my life. So thanks to everyone. Thank you, sir.

Yes, I'm about to crack, Tony.

Now the results. Today, we reported adjusted EBITDA of $2.4 billion for the third quarter, generating $1.8 billion of distributable cash flow, providing 1.5x coverage. Additionally, we retained $635 million of DCF.

When I look at the third quarter results, I'm reminded of the long anticipated projects we're commissioning in the fourth quarter. Third quarter results were lighter than expected, but far from discouraging as we look ahead to year-end and into 2026. After a 3-month delay, Frac 14 is now in service and will contribute to our results going forward. The Bahia pipeline and Seminole pipeline conversion will come online in tandem, adding capacity to our NGL pipeline system and returning capacity and flexibility to our crude oil pipelines. We originally planned for these projects to be completed around midyear, but we look forward to completing them in the remaining months of 2025 and what they'll deliver.

Our PDH plants are looking up with PDH 1 averaging 95% of nameplate, and PDH 2 showing similar promise as it resumes operations following a third quarter turnaround to address coking in the fourth reactor, an issue the technology licensor order has committed at the highest levels to resolve. If you add all that up, I see a lot of upside that was pushed out of the third quarter.

As you know, our petrochemical facilities at Mont Belvieu have faced their share of opportunities and challenges. Enterprise is built on engineering and operational excellence, and Randy and I couldn't be more proud of the incredible work our petrochemicals teams have done to bring these assets up to our standard. We've never been more confident in the team we have in place today.

With the Neches River terminal set to be completed next year, we're nearing the end of a multiyear, multibillion-dollar capital deployment cycle that began in 2022. These strategic investments, including pipelines, marine terminals and key acquisitions puts us in a great position to capitalize on long-term growth from the Haynesville and Permian Basins.

Finally, I'm sure Randy is going to hit this, but I kind of enjoy stealing his thunder from time to time, to say this morning, we announced a $3 billion increase to our buyback program, taking it from $2 billion to $5 billion. While we see plenty of opportunities to efficiently expand our footprint in the future, we are also well positioned to continue our strong track record of returning capital to our unitholders. Growing distributions will continue to be our primary focus, but this expanded program enhances our flexibility to grow buybacks alongside rising free cash flow. We're excited about the next chapter, not just in the years ahead, but in the decades to come.

And with that, I'll turn it over to Randy.

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

In the third quarter, the partnership purchased approximately 2.5 million common units under its buyback program for $80 million. Total repurchases for the first 9 months of 2025 were $250 million or approximately 8 million enterprise common units, bringing total purchases under our buyback program to approximately $1.4 billion. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 3.5 million common units on the open market for $114 million during the first 9 months of 2025, including 1.2 million common units on the open market for $37 million in the third quarter.

For the 12 months ending September 30, 2025, Enterprise paid out approximately $4.7 billion in distributions to limited partners. Combined with the $313 million of common unit repurchases over the same period, Enterprise return total capital was $5 billion, resulting in a payout ratio of adjusted cash flow from operations of 58%.

As Jim mentioned earlier, we expect an inflection point in discretionary free cash flow in 2026 as we have completed a 4-year period of large investments, both organic and acquisitions that enhanced our -- have enhanced and expanded our integrated footprint in the Permian and Haynesville basins and our premium -- premier wellhead to market businesses serving domestic as well as international markets via our marine terminals.

With the completion of the major projects such as Bahia NGL pipeline, and Neches River Terminal, we continue to believe our organic growth capital expenditures in the near term will return to our mid-cycle range of approximately $2 billion to $2.5 billion per year and largely consist of pipeline expansions and smaller projects, both on the supply and demand side and natural gas storage, treating and processing facilities.

As Jim noted earlier, we announced our Board has approved an increase in our common unit program of -- to $5 billion. The program now has $3.6 billion in capacity, allowing us to increase the amount of our annual buybacks as our free cash flow increases. In terms of allocation of capital, we see cash distributions to partners growing commensurate with distributable cash flow per unit in the near term with discretionary free cash flow being evenly split between buybacks and retiring debt. Growth in cash distributions to partners can be further enhanced by the percent of common units we retire through buybacks.

Total capital investments were $2 billion in the third quarter of 2025, which included $1.2 billion for growth capital projects, $583 million for the acquisition of natural gas gathering systems from Occidental in the Midland Basin, and $198 million of sustaining capital expenditures. Our expected range of growth capital expenditures for 2025 and 2026 remains unchanged at approximately $4.5 billion for 2025, and $2.2 billion to $2.5 billion for 2026. We continue to expect 2025 sustaining capital expenditures to be approximately $525 million.

Our total debt principal outstanding was approximately $33.9 billion as of September 30, 2025, assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio is approximately 17 years. Our weighted average cost of debt was 4.7% and approximately 96% of our debt was fixed rate. At September 30, we had consolidated liquidity of $3.6 billion, which includes availability under our credit facility and unrestricted cash on hand.

Our EBITDA -- our adjusted EBITDA was $2.4 billion for the third quarter and $9.9 billion for the last 12 months. As of September 30, our consolidated leverage ratio is 3.3x on a net basis after adjusting debt for the partial equity treatment of the hybrid debt and reduced by the partnership's unrestricted cash on hand. This is above our leverage target of 3.3x, plus or minus 0.25 or a range of 2.75 to 3.25x. This is due to the capital expenditures on our large projects such as NGL fractionator 14, Bahia NGL pipeline, Neches River Terminal and the acquisition of Oxy's Midland gathering system being included in our debt balance without EBITDA included in our trailing 12 months of EBITDA. We believe our leverage will return to our target range by year-end 2026 when we have a full year of EBITDA from these projects.

With that, Libby, we can open it up for questions.

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

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

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

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

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

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

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

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

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

I do. I remember that Tony.

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

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

Thank you, so much.

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

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

Going to the capital allocation side of things. On the upsized buyback authorization, would you all talk about or just provide more details on the capital allocation outlook for the next couple of years. What do you see at this point as a steady-state run rate for CapEx? And do you expect to buy back stock on a more ratable basis given the visibility in free cash flow growth? Or will it be more opportunistic and dependent on market dynamics?

Okay. Theresa, this is Randy. Yes, I think when we come in and think about sort of as you put over the near term, the next 2 or 3 years on organic growth CapEx, we do see it in the $2 billion, $2.5 billion range. With the projects that we currently have announced, and with a few that we've got pretty good visibility on that we think will come forward that's included in expectations. Next year, we see really $2.2 billion to $2.5 billion. Could next year get to $2.6 billion, $2.7 billion? It could. But we don't see it going to $3 billion. And so I think that's sort of where we are on the CapEx side.

And so as a result, we will have -- given those numbers, we'll have some free cash flow to deploy. And again, at this point, looking to split it between buybacks and debt paydown. And I think because we're leaning in a little bit more on buybacks than what we've done over the last 2 or 3 years, there could be an element of programmatic buybacks in there as well as, I think, with the component of debt paydown that we have in there as well, that gives us a little bit more flexibility to be opportunistic. So really, I see the buybacks having a component of both programmatic and opportunistic.

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

Yes, Theresa, this is Justin. So clearly, a lot of headlines out there with respect to people reacting to kind of the ongoing closures and potential future closures in California. Two points to make. There's a lot to unpack with respect to the projects out there, whether or not they go or not, and then also what the future closures or potential closures in California will be.

But we'll hang our hat on two things with respect to the system. One is we run a unique corridor pretty much direct to Salt Lake. And to the extent that Salt Lake gets net shorter as a result of these projects, then we're going to stand to be the beneficiary. And then if you zoom out to our overall product system, both our TW system and our legacy TE system benefit from Mid-Continent pricing being at a premium to the Gulf. And really, all three of these projects that have been announced do some degree of that. So our overall product system will benefit by -- if any of them go. Again, early days, we just have to see how it plays out.

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

I also wanted to wish congratulations to Tony. We've really enjoyed working with you. So congrats.

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

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

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

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

You did.

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

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

Is Natalie in here?

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

Mike, well, this is Natalie Gayden. I would say in Midland, volumes are outperforming our expectations. I think the last time I sat on this call, I gave some well connects just for color. The well connects in '26 are up 25% from what I told you last time. We're now expecting almost over 600 wells to be connected to the system next year. A lot of that fourth quarter surge from the original 500.

In the Delaware, same growth trajectory. We've got a record number of wells being connected to the low-pressure system we've built up in the Northern Delaware. That growth curve is steepening for Delaware and the trajectory remains intact and increasingly constructive.

And then lastly, I'll just -- I'll say this, and I may say it more than once, but we don't talk about base volume durability and PDP and how it holds in on gas. I think that's sometimes what people miss, and I'll just give you an example. We have a producer in Midland that finished their development program a year ago. Today, in Midland, those volumes are flat with where they were then. So in some part of the PDP and the base volume and durability of that volume, I think that's just upside.

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

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

How are you contracted on Seminole?

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

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

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

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

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

Okay. Are you fully contracted on ethane and LPG?

We're around 90% contracted on LPG, and we are fully contracted on ethane...

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

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

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

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

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

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

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

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

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

This is Graham. On PDH 2, we've had some issues with coking on the fourth reactor. As Jim mentioned in his remarks, we've developed new operating procedures and made some modifications during the outage to address some of those, and we continue to work with a high-level team from our licensor to improve the process.

And if you look at -- on PDH 1, if you look at our run rate for the quarter, we had a very high run rate, a few minor issues, but the team out there has really done a great job of being able to reduce some of the impacts, and we know some of the -- we've got line of sight on fixing a few of the issues that we have. So we're very optimistic going forward that the PDH run rates are going to continue to increase from where they've been, and we'll see a great improvement in 2026.

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?

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

Our next question comes from the line of AJ O'Donnell of TPH.

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

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

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

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

How do you see our storage?

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

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

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

This is Natalie Gayden. That asset acquisition was strategic, and I'll just -- let me just lay it out for everybody that doesn't remember. It's a 75,000-acre acreage dedication. It's got over 1,000 drillable locations. So an opportunity of that scale is quite rare. They bolt -- the assets bolt on pretty seamlessly to our existing footprint and extends the reach. We -- it will unlock for us an incremental 200 million a day almost immediately, let's just call those revenues coming to us in really 2027. We love assets that are already producing gas, but then the development for that asset is going to be quite constructive and strong.

Like any other asset or footprint that we've purchased, again, being in an area and having the reach is the way we get incremental packages of gas onto our system. So we've already seen synergies, yes, with the acquisition of that asset.

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

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

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

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

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?

It's Natalie show...

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

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

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

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

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

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

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

Thank you for standing by, and welcome to Enterprise Products Partners L.P Second Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

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.

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, about 1.6x coverage, and we retained $740 million of DCF. We set 5 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 products and petrochemicals. And we have even more plant frac and dock capacity coming online over the next 18 months. We've got nearly $6 billion worth of organic growth projects entering service. That includes 2 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 3 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 barrel per day by Y-grade pipeline and our frac port team these investments bring more volumes into our NGL value chain.

We started operations at our Natus River terminal. Initially, the facility will have the capacity load ethane at 120,000 barrels a day. In the first half of 2026, the facility will be fully operational or 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 and 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 [indiscernible] and LPG.

We managed to navigate these disruptions. That said, we've been clear about the risk of recognizing U.S. energy exports. These kind 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. We are growing rumors and 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 range from $0.10 to $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 to current market pricing and by a 60% drop in spot rates. Although increased throughput across our Houston Ship Channel pipeline system, help mitigate the decline. It doesn't change the fact that this market has fundamentally shifted. Despite the challenges, however, we remain well positioned to succeed. Our competitive advantage from our existing export infrastructure enables us to make customer needs through brownfield expansions, where new build economics simply don't work, and we will aggressively depend our position.

The appetite for U.S. 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 in the market, not winning demand. [indiscernible] is a supply-driven business, and our network of assets reflect that. The majority of our capital projects currently understored construction directly support our supply strategy, which applies in the whole story. What sets us apart is our extensive connectivity to end users.

We are directly or indirectly linked. The 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 Natus River terminal expanded LPG loading at EHT, and increased ethylene export capability at Morgan's Point. We've taken the deliberate step [indiscernible], enhance and expand our downstream footprint, strengthening our access to global markets.

And with that, Randy, I'll turn it over to you.

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 quarter 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%, $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 PDH 1.

Distributable cash flow provided 1.6x coverage of the distribution declared for the second quarter 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 unitholders 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 just a combined 5.5 million common units on the open market of $171 million during the last 12 months, including 1.3 million common units on the open market for $41 million during the second quarter 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 unitholder after privately held EFCO 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 remain unchanged and at $4 billion 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 June 30, 2025, assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio was approximately 8 hours.

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 3.1x on a net basis after adjusting our debt for the partial equity treatment of our hybrid debt and reduced the partnership's unrestricted cash on hand. Our leverage target remains at 3x 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 Instructions] Our first question comes from the line of Spiro Dounis of Citi.

First question, I just want to maybe take a 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? Should we expect these processing plants to come online pretty full as well?

Zach, what would be your ramp-up on [indiscernible].

[indiscernible] will come up completely full. NRT will see a ramp as VLECs are ordered and not only can chime in, but I think the processing plants are going to have a pretty quick ramp to them as well.

Yes. That's right. Delaware and Midland combined is probably around a 90% utilization today. But remember, we just brought those 2 plants up -- by the end of the year, fourth quarter, mainly driven [indiscernible]

Wilbert here come up at. Yes.

But he 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 to 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, do you start ratcheting up the buyback in anticipation of 2026 being a lean year? Or really not until we get into it, do we see any sort of, let's call it, step change in the buyback program.

Spiro, this is Randy. We had said actually last quarter that our expectation this year was we would probably do anywhere from $200 million 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 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 rolling off much more free cash flow.

Our next question comes from the line of Jean Ann Salisbury of BofA.

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?

this is Doug. So it's -- from our perspective, specifically on LPGs, we stay in 85% and 90% contracted through the balance of the decade. And as far as our strategy, probably 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.

Jean, the other thing I think is important is that export facility as a way of being a magnet for our pipelines and our fractionators and our storage.

That makes sense. And then 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? And how do you think about that?

I think I'll than 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 in oil is 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, any way you cut it, all signs point to the Permian Basin continuing to get cashier really for years to come. There's no question about it.

I think 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 question.

What's that?

It's a great time, Tony.

Okay. There's a lot that's happened over the last 60 to 90 days First and foremost, OPEC has abandoned their long-standing market stability roll in favor of market share and on the way to put a couple of 2 million barrels of incremental production on in just a 6-month time period.

That's a lot. And then we had the Israel and Iran conflict breakout to a full fledge war and all the oil facilities in Iran and throughout the Middle East [indiscernible]. So thus, we had the word premium taken out. So all that being said, there's a lot of pressure 1 could see on oil. Meanwhile, we're sitting here in summer driving season around the world and strong demand in the Middle East.

So the question is, when the strong demand end, summer driving season ins and Middle East quick using all the oil for electrical generation, what happens to oil and I guess, Jean respectfully, I see there's a lot of people that are -- that have some pretty dire forecast. And we feel differently, and I think I'll just point out the reason we feel differently is OPEC has been shorting the market, at least 2 million barrels a day for 2 years running and more on top of that.

So there is a massive hold to be able to put oil into when and if the price drops -- so assuming we have a price drop and we moved from backwardation to contango, oil is going to get a signal to trade into storage, and that's the way we see it. So 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 U.S. producers? We had a brief period where we touched $57. But we're at 65% this morning.

And really, when you look at '26, '27 all the way out 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 in new pipelines to take away and really Permian producers bottom line is extremely profitable. So I think what we're going to see during earnings 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 on the hedging '25, '26 and maybe even some of them '27. From a fundamental standpoint, that's how we see it Natalie. What are you seeing? Are we?

Yes, we are not hearing anything different than we always spoke to in our last earnings call. We actually did get a surprise from 1 of our producers who brought wells forward in 2026 in our production plans. There are a few production areas, too, in our portfolio where it's not declining as expected. And obviously leave you with this, in Midland, this year, we will have brought on 463 wells. Next year, we are -- we will -- we have 498 on the schedule. Just to give you some color.

-

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

I want to go back to the topic of NGL exports. And Specifically, what are the lessons we 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 you 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?

Doug, do you want to take it?

Yes. So if you look at what happened with the BIS requiring 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. But if it was going to be sustained, I could see if there's any a challenge for ethane structurally here in the U.S. But what it has done and where it's been a problem if you really compromise the U.S. brand for reliable supply and energy security when you just cut off a counterparty like that.

In fact, I would 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 is coming to the U.S. to get get ethane. So from that perspective, it's been disruptive, but in the short term, we were able to manage through it with our diverse contract mix.

And then within the Pecan and Refined Products 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 these spread-based businesses. Can you touch a little bit on the incremental supply you see Optane that will persist from here?

Yes. 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, and we haven't met expectations about what our onstream time should be. As far as our beef and octane enhancement goes. We've had really a record last 3 years of high margins.

And as Jim touched on in the opening remarks, we've kind of returned to historic kind of margin. So they're still really good. I mean it's 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, the we've seen margins improve just part of that will probably be in driving season. We still see the pressure from China. Historically, MTBE was more of a regionally 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. And we started seeing that pressure, and that's some of the reason why we've seen some weakness.

Our next question comes from John Mackay of Goldman Sachs.

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? And then maybe any comment you can make on a related side for anywhere else in the portfolio or particularly the Permian NGL pipes.

I'll take it and then Doug you take it. I think you heard Doug say we're 85%, 90% contracted on LPG exports through the end of decade. We're going to be full here and simple, and we'll defend it ever how we have to. And Doug, you got anything to add other than [indiscernible] to be full?

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

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

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. 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.

Our next question comes from Michael Blum from Wells Fargo.

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? And could that have a meaningful impact for you guys?

Not, necessarily where we are located, I guess, the uptick in activity. I don't know if you're talking about the recent acquisition of a player there. But as far as we can tell, our [indiscernible] pretty stable flat to slight really small growth.

Okay. Great. I appreciate that. And then just maybe just a follow-up for Tony. I 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 if you had to tweak that today, there would be pretty minor tweaks to what you were seeing back in April.

Michael, that's a great question. I really appreciate it. Yes, there -- if we had to tweak it today, given the given the profitability of the Permian producer, those tweaks would be small. So from a black oil standpoint, we were calling from 25 through 27, I think we were calling for 800,000 barrels of growth.

Could that be 7 Yes, certainly 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 6%. 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 coming, Michael, and they say they're going to 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 -- I think we're on target, Michael. I think we're on target. And we've said before that liquids forecast is is on target to meet our forecast or producers continue to drill gas here. So we feel great about our [indiscernible] forecast also. And then Natalie confirmed and Justin is confirmed, Zach is confirmed. That's what we're seeing in the business. 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.

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

There are a lot of announcements on potential LNG projects and there is a belief that [indiscernible] could be supplying some of them. Can you talk about your leverage to the Haynesville shale, maybe talk about the Acadian gas system little.

So our [indiscernible] 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 going to achieve on that pipe relative to historical is 2 to 3x what we've seen before.

So a little bit more increase in activity, obviously, in the Haynesville with a price of gas, and we'll reap benefits from that.

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

Yes. No, I think when we came in and sort of gave future guidance of $2 billion to $2.5 billion, that's really taking 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.

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

I want to clarify some of the earlier questions around LPG exports. So you're 85% to 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?

This is Doug. That is correct.

Okay. Great. And then I had 1 on Natus River. So the major projects under construction bucket went down $2 billion from $7.6 million to $5.6 million. It looks like that's 2 processing plants and Phase 1 of the export facility. That implies the capital cost could be maybe $1 billion or more for Phase 1 of Nature River. Am I thinking about that right, just as a ballpark?

Yes, that's in the ballpark.

Okay. would Phase 2 be similar to that?

Not that much.

Our next question comes from the line of Brandon Bingham

of Scotia Bank.

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 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 in LNG? Or just how should we think about all of the cash gen moving forward?

I imagine Randy is going to try to give it to you guys.

Yes, Brandon, I don't see us -- and I'm trying to read where you're going with your question is are you asking would we make passive equity investments in LNG facilities.

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

No.

Yes. 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 is the greatest opportunity across your operations right now?

Yes. I think 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 an export system and those fees are cents per pound, not sense per gallon.

Our next question comes from the line of Jason Gabelman of TD Cowen.

I'm afraid I'm going to ask another 1 on LPG exports. And 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 in contracting with those customers?

I can't -- this is Doug. I can't speak for what our competitors are doing relative to their CapEx or how much it cost 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, and that's another competitive advantage we have, and our customers are here to continue to take the LPG exports from our facility at a competitive fee.

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 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.

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 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. And 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. And how much -- does that kind of frame your strategic decisions on capital allocation moving forward?

Do you want to take it?

Yes. Let me... 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 Haynesville. The sectors that we support the downstream sector, 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 organic standpoint as opportunities arise.

When you come back in, especially 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. And 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 and where we see opportunities to deploy it, we will. But honestly, I think discretionary free cash flow is really about to take a a step-up in 2026, 2027, and that will give us an opportunity to come and return more capital to our investors.

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

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

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