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Enterprise Products Partners L.P. misses on earnings expectations. Reported EPS is $0.64 EPS, expectations were $0.705.

Operator: Thank you for standing by and welcome to Enterprise Products Partners L.P.’s First Quarter 2025 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be question-and-answer session. [Operator Instructions]. I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

Libby Strait: Good morning, and welcome to the Enterprise Products Partners conference call to discuss first 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 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 will turn it over to Jim.

A.J. Teague: Thank you, Libby. We’ve got a special guest with us today. Sam Hawley, our Vice President of Wholesale Propane is with us, and I wanted — we wanted to publicly acknowledge his contributions to the company. Sam has been in the industry over 30 years, with Enterprise over 20 years, and I can say I’ve never known anyone with more passion for our company, for his business and for his people. He will be missed my friend. With that, I want to cover a few highlights in the first quarter and summarize the things we look forward to. We had adjusted EBITDA of $2.4 billion, $2 billion Bcf, 1.7x coverage, $842 million of retained DCF, two financial records and five operational records. In total, we moved 13.2 million barrels of oil equivalent a day and 2 million barrels a day of liquid hydrocarbon exports.

Relative to our PDH facilities, our PDH 1 facility was down for 63 days during the third — first quarter of 2025 for unplanned maintenance. As of last week, both our PDH plants are online and no major downtime is planned at either plant for the remainder of the year. If both PDH plants have been up and running during the first quarter, we would have easily exceeded $2.5 billion. We continue to benefit from growing production in the Permian and consistent domestic and international energy demand pool across our systems. For the remainder of 2025, we look forward to bringing on two guest processing plants in the third quarter in the Permian, one each in the Delaware and Midland Basin, the Bahia NGL pipeline in the fourth quarter, Frac 14 at our Mont Belvieu complex in the third quarter, the first phase of NGL exports on the Neches River in the fourth quarter and enhancements of our ethane and ethylene terminal at Morgan’s Point also in the fourth quarter.

I’m sure Tony or Natalie will discuss our Permian outlook in more detail during Q&A, but there’s a large backlog of wells expected to be connected to our gathering and processing systems between now and the end of the year that will feed our downstream NGL value chain. On the other side of the equation, exports, I’ve never U.S. hydrocarbons get this much attention worldwide. But now it appears China is going to exclude ethane and ethylene from their tariffs to protect their petrochemical business. Currently, LPG has not been excluded from the Chinese part tariffs, but admittedly, the situation is fluid. Regardless, the market has already gone to work rerouting barrels between the world’s biggest LPG suppliers, the U.S. and the Middle East and the biggest importing countries being China and India.

It’s important to note that even before the tariff calls, nominations at our docs from May indicated that our customers’ behavior was virtually unchanged from prior months. The bottom line is the world needs U.S. oil, natural gas, and natural gas liquids to provide for their people and to grow their economies. Relative to all the chaos, the beauty of free markets is price always works. Price creates supply, price creates demand in the right places and for the most part, in a timely manner. I can’t help myself, but today with comments on Washington. Stating the obvious a lot is going on that is causing nothing short of chaos around the world. Energy is not excluded. No one can tell how all the pieces land. So I think we must fall back on what we think we know.

President Trump was extremely fuel oil and gas in his first term and ran in on a second term on a pro oil and gas platform, stressing that we must unleash and expand our domestic energy production and exports. There is also no doubt that the Trump administration understands the importance of U.S. hydrocarbons to our economy, global markets and our balance of trade. Amid all this uncertainty, I have the core belief that when the dust settles in game of this administration’s policies, laws and regulations is intended to promote U.S. energy, not just for the next four years, but for decades. Enterprise is one of the largest exporter of hydrocarbons and is significantly increasing our capacity to gather, process transport, upgrade, distribute and export hydrocarbons.

We feel great about our assets and the investments we are making and what they mean to our future. With that turning to Randy.

Randall Fowler: Okay. Thank you, Jim, and good morning to everyone. I’ll start off with the income statement. Net income attributable to common unitholders for the first quarter of 2025 was $1.4 billion or $0.64 per common unit on a fully diluted basis, which compares to $0.66 per common unit for the first quarter of 2024. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital was $2.1 billion for both the first quarters of 2025 and 2024. We declared a distribution of $0.535 per common unit for the first quarter of 2025. This is a 3.9% increase over the distribution declared for the first quarter of 2024. This distribution will be paid on May 14th to common unitholders of record as of the close of business on April 30th.

In the first quarter, the partnership purchased approximately 1.8 million common units off the open market for $60 million. Total repurchases for the 12 months ending March 31, 2025, or $239 million or approximately 8 million EPD common units, bringing total purchases under our buyback program to approximately $1.2 billion. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 6 million common units on the open market for $181 million during the last 12 months. This includes 1.1 million common units on the open market for $35 million during the first quarter of 2025. For the 12 months ending March 31, 2025, Enterprise paid out approximately $4.6 billion in distributions to our limited partners, combined with $239 million of common unit repurchases over that same period enterprises total capital return was $4.9 billion, resulting in a payout ratio of adjusted cash flow from operations of 56%.

Since our IPO in 1998, we have returned $58 billion to unitholders in the form of distributions and buybacks. Total capital investments in the first quarter of 2025 were $1.1 billion, which included $964 million of growth capital, both for growth capital projects and $102 million of sustaining capital expenditures. Our expected range of growth capital expenditures for 2025 and 2026 remains unchanged. For 2025, this is $4 billion to $4.5 billion. And for 2026, it’s $2.0 billion to $2.5 billion. We continue to expect 2025 sustaining capital expenditures to be approximately $525 million, which includes a planned turnaround at our octane enhancement plant later this year. Our total debt principal outstanding was approximately $31.9 billion as of March 31, 2025.

Assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio was approximately 18 years. Our weighted average cost of debt was 4.7%, and approximately 96% of our debt was fixed rate. Our consolidated liquidity at the end of the quarter was approximately $3.6 billion, including availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA for the quarter was $2.4 billion, and for the last 12 months was $9.9 billion. As of March 31, 2025, our consolidated leverage ratio was 3.1x on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and reduced by the partnership’s unrestricted cash on hand. Our leverage target remains 3.0x plus or minus 0.25x. With that, Libby, we can open it up for questions.

Libby Strait: Thank you, Randy. Operator, please open the call for questions.

Operator: [Operator Instructions]. Our first question comes from the line of Jean Ann Salisbury of Bank of America. Please go ahead, Jean Ann.

Jean Ann Salisbury: Hi, good morning. You are a major LPG exporter. Can you tell us — you touched on this in your comments, but can you tell us what you’re seeing real time today is all U.S. LPG currently being rerouted away from China? And as my follow-up, more broadly, can you talk about how you see the competitive landscape for LPG exports here in light of the tariffs and significant capacity being built by you and others? Thank you.

Tug Hanley: Hi, Jean, this is Tug. So on the first prong of your question, we are currently seeing the trade flows work the balance. We have not seen a disruption on any of our exports on ethane or LPG. We have limited direct exposure on LPG and ethane to China. We don’t have a single contract with a Chinese entity. Our counterparties are typically international companies. You know how to navigate international volatility. Now what our customers export in China is approximately 32% on LPG and 40% to 50% on ethane. On the second prong, your question about the competitive landscape, the capital for our brownfield expansion of the Houston Ship Channel is around $400 million, and we get 300,000 barrels a day of capacity for that investment.

So compared to the other announced projects and their respective capital, our expansion is the most capital efficient on a per unit basis of export capacity. We expect a significant capital advantage to translate into the most competitive terminal fees in the market for our customers.

Jean Ann Salisbury: Great. That’s helpful. I’ll leave it there.

Operator: Thank you. Our next question comes from the line of Spiro Dounis of Citi. Please go ahead, Spiro.

Spiro Dounis: Thanks operator. Good morning team. Teague wanted to go back to some of the projects you had sort of listed off coming online later this year. I think in total, something like $6 billion of projects starting up in 2025, which just sort of basic midstream multiple gets you about $800 million of incremental EBITDA. So curious, how much of that would you say sort of hardwired doesn’t really rely on a lot of incremental growth here? And how should we think about that EBITDA ramp in cadence? It sounds like more of a ’26 item, but curious how to think about that.

A.J. Teague: Spiro, I’m having a hard time understanding it.

Spiro Dounis: Okay. So you’ve got $6 billion of projects, and that’s about $800 million of EBITDA, if you put a pretty standard multiple on it. I guess I’m just curious how you’re thinking about the ramp-up and the cadence of that $800 million of EBITDA coming online. Is that all a ’26 item? Is that going to take years to kind of come to fruition?

A.J. Teague: What’s the ramp on your own processing plants Natalie?

Tug Hanley: Our processing plant, when they come online here in the next couple of months will be close to full in Midland, and let’s call it, 60%, 75% full in the Delaware. It’s pretty fast for us.

A.J. Teague: Okay. Exact where will you be on your Frac 14.

Randall Fowler: I don’t think we’ve ever shown that we haven’t brought up a frac not full.

Spiro Dounis: Tug are just in exports?

Tug Hanley: Yes. I mean on the exports, we’re 85% to 90% contracted on LPG, I think I mentioned that last earnings call, and we’re now for an upper band of that. So as those projects come online, they’re contracted.

A.J. Teague: We have, I think, it’s Spiro, 12 projects that we list, eight of those projects are supply projects and the remainder are on market projects. And we’re pretty confident that they’re going to be fairly full when they come up.

Spiro Dounis: Great. Good to hear, Jim. Thanks for that. Second question, maybe over to you, Tony. Obviously, you put out your fundamental update a little less than a month ago. Obviously, a lot has happened since then and in and around that time. So just curious maybe how you’re thinking about some of the assumptions that went into that initial forecast, if anything sort of changed in the last month or so, I realize that it’s still to some degree early days here. And to the extent you’re seeing any sort of producer reaction based on some OPEC supply returning to the market?

Anthony Chovanec: Yes, Spiro. Let’s first talk about what we show, what our numbers show happened in 2024. I think that’s a good place to start. For the Permian Basin, I’ll focus on the Permian Basin. We show that black oil production grew about 325,000 barrels in 2024. Rich gas, about 3.5 [indiscernible] and NGL is about 300,000 barrels. We run our base case that we recently published on $65 WTI and $3.50 natural gas at Henry today, that oil price as we go forward over the next three to five years sits closer to $60 than it does $65. In general, we and others believe that $55 to $60 puts the Permian more or less in a maintenance mode and closer to $50 takes the Permian probably below maintenance. It’s likely the largest and soonest impact will be on smaller players, those running less than three rigs.

Out of 300 rigs running in the Permian, about 75 of those are operated by small operators that have three or less rigs running. So that’s probably the most immediate impact you’ll see. You are hearing some of the producers at this point. And Natalie, I guess we’ll speak to it here in a second, talk about dropping — I’m going to call [indiscernible] and 2 Cs, but no big step function in what they are planning to do. I think the most important point to make, and we’ve been trying to make it for at least the last three years, because crude declines are steeper, the natural gas. We’ve run a theoretical flat case for Permian between now and for Permian Black oil between now and 2027 and to stay right where it is. And in that case, rich natural gas to grow between 1.3 and 1.5 Bcf a day between 927, call that a couple of hundred thousand barrels a day of natural gas liquids.

That’s what the fundamental show, Natalie, tell us what your producers are telling you on time.

Natalie Gayden: Yes, I’ll just add, as it relates to enterprise and on the gathering and processing business by design. Our producers are some of the largest and most sophisticated and best positioned players in the basin. And then a large percentage of our biggest producers ex integrated majors are either entirely or primarily focused on the Permian. Just to put that into perspective, we connected over 1,000 wells in ’24, and we’re expecting a similar number of well connects from line of sight that we have in 2025, but it’s very second half oriented.

Spiro Dounis: Got it. That’s a great color. I’ll leave it there. Thank you team.

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

Theresa Chen: I wanted to touch on the petchem and refined products segment. With the return to utilization or full utilization for PDH, what is your outlook for the segment for the remainder of the year? And then maybe if you could touch on some of the smaller components as well, including the conversion of your — the 20% of your propylene production to fee-based how much volumetric exposure do you have there as well as the octane spread for MTPE to U.S. Gulf Coast gasoline? What is your outlook there as well, please?

Christopher D’Anna: Hi, Theresa, this is Chris Dan. That was a lot. I’ll try to hit all of it. On PDHs, both of them today are running very well. Even PDH 2, although it’s not meeting the full expectations, we are meeting our contractual obligations on that. So that’s a big step from where we were even the last call. And our expectation is that we continue to run those clients at the same rates, we are running today. PDH 1 is running above nameplate by the way. I did have a very rough first quarter, as you saw in the release. But the issues that we had were mechanical, not anything else and we think that we’ve resolved those. Then on the RGP, PGP, that has been something that we’ve been working on for a little bit, most of our refinery suppliers wanted less exposure to RGP and more on the PGP side.

So we felt it was a win-win. We got what we thought was a very fair fixed fee going forward. So that’s going to reduce our volatility on the splitter margins. And then let’s see, I make sure I cover your questions. I think the last one was around octane spreads?

Theresa Chen: Yes.

F. Christopher D’Anna: And so we’ve talked about in the past how we hedge the normal to RBOB spreads. So we’ve done that this year. We have about 75% of our spread hedged. And then the overall MTBE has been a little bit weaker so far this year. And typically, we see in the last half of the year, kind of in the summer Fall time frame as guests as driving season picks up, we see that widen a bit. So that’s kind of what our expectation is looking forward. Of course, there’s no forward curve to look at for that product.

Theresa Chen: Thank you, Chris. I will leave it there.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet of JPMorgan. Your line is open, Jeremy.

Jeremy Tonet: Hi, good morning.

F. Christopher D’Anna: Hi, good morning, Jeremy.

Jeremy Tonet: I just wanted to touch on the topic of buybacks, if I could and how recent market price volatility might have impacted your view on the near term there and thoughts, I guess moving forward in ’26 as CapEx tapers off a bit there if there might be room for buybacks to step up a little bit next year?

Randall Fowler: Yes, Jeremy, I appreciate the question. Yes. I think we covered it on the fourth quarter call. And really, we’re in the same place today that if we come in and look over the last 12 months, our excess distributable cash flow is about $3.3 billion. And in the way I think about excess distributable cash flow. So you’ve already taken care of the distribution and then been the next is to go ahead and cover growth CapEx. And then after that, then you have — which I have left is available for buybacks and for debt paydown. And what we had highlighted on the last call, if you come in and you look at mid-single digits growth in cash flow per unit, once you get out to 2026, it’s probably putting you somewhere around $3.6 billion area for excess DCF. And with growth CapEx in the range of $2 billion to $2.5 billion, that leaves you maybe $1.5 billion available for debt paydown and buybacks. So again, 2026 should be a big change in excess distributable cash flow.

Jeremy Tonet: Got it. Thank you for that. And if I could, maybe just as it relates to the management team, has seen departure recently. And so when might we hear more, I guess on the COO role or any other changes in management?

A.J. Teague: This is Jim. I love what Randy says. He said, we think in terms of decades, not quarters, we got a bench that is unbelievable. We’ve got young to middle-aged talent, and I’m not worried at all about what our succession plans are and that’s about all we’re going to share.

Jeremy Tonet: Got it. Fair enough. Thank you.

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

John Mackay: Hey, good morning. Thank you for the time. I want to go back to the NGL exports and some of the kind of global dynamics, understand the comments on tariffs, ultimately, maybe at least for right now not being a major issue. Just curious, are you seeing any sort of slowdown though in terms of a broader macro impact meaning we could see kind of lower demand in Asia for some of these products and, therefore, see some knock-on effects? Or is everything going pretty well there so far?

A.J. Teague: I’m going to hand it off to Tug. This is Jim, and I’ll start. We’ve recently signed contracts with the Southeast Asian companies, and they’re not small. And I’ve not seen any change in behavior at our docs. Do you want to pick it up? Tug, are you sold out on your ethane export — on your export?

Tug Hanley: Yes, we’re fully contracting our ethane exports and…

A.J. Teague: LPG.

Tug Hanley: And like I mentioned earlier, 85% to 90% on our LPG. But if you look at it, it doesn’t change the fundamental fact that there is a demand slowdown internationally. All that means is that propane has to continue to price lower to compete with MAP because ultimately, the barrel has to clear. We can slow a lot of propane as a country in the U.S., but we cannot do it indefinitely. So price will solve that. We’ll displace naphtha or other products.

John Mackay: All right. That’s clear. Thank you. And maybe just picking up on a couple of threads from earlier. Tony, your market forecast kind of reflective of the — some of the changes you made last couple of years, higher GORs, stronger NGL outlook even if oil is a little flatter. Is this changing your view at all on how you’re thinking about the ’26 CapEx budget with that in the context of maybe a macro slow down a little bit. Is there a risk to the upside or downside to that $2 billion to $2.5 billion of CapEx you’re framing up for next year?

Randall Fowler: Yes. John, I’m going to jump in here because really, when we look at 2026 and look at $2 billion to $2.5 billion of growth CapEx. The bulk of that CapEx is related to this $7.6 billion worth of assets under construction. So if I come in and if you say — so our range expectation is $2 billion to $2.5 billion. And let’s just say $2.5 billion. That’s probably $600 million to $700 million worth of unidentified growth projects that still may be in development, but nothing has been FID. So if you even take that away, that comes in and tells you we probably have $1.8 billion, $1.9 billion in growth CapEx next year just to come in and finish construction of the projects that have already FID. Does that help?

John Mackay: Yes, that’s clear. Appreciate it, thank you.

Operator: Thank you. Our next question comes from the line of Michael Blum of Wells Fargo. Please go ahead, Michael.

Michael Blum: Thanks. Good morning everyone. I wanted to sort of follow up on that the CapEx question, maybe a little more detailed. If tariff policy does slow global demand on a more consistent basis, and this isn’t a temporary situation. Would you consider slowing some of your NGL expansion projects? Or are those just kind of fully contracted committed customers? So they’re going to move forward regardless of what happens on tariffs.

A.J. Teague: You’re talking about what we have under construction now?

Michael Blum: Under construction and plans. Yes.

A.J. Teague: I think we’re pretty well contracted. I can’t see us slowing down on what we’ve got under construction.

Randall Fowler: Yes. And Michael, I think one of the ways we think about it. Tony commented earlier, that even if you saw crude production go flat, you still have call it, 1.5 Bcf a day of natural gas production growth out of the Permian, which represents maybe 200,000 barrels a day of NGL growth coming out of the Permian. So again, the projects that we have under construction, I mean the bulk of them will be finished by the end of the year with some carryover with some carryover on Port Neches, but a lot of them will be finished by the end of the year. So it’s hard to see any slowdown from that standpoint. And I think one of the things to also keep in mind is, and I think Tony has had it in past Investor Day presentations, that when you come in and you look at crude oil demand growth and ethylene and propylene demand growth.

There are about, I think crude may be 0.9x GDP growth. Ethylene growth is like 1.2, propylene maybe 1.3 GDP growth. And the economists that I’ve seen as far as them try to come in and forecast the impact of tariffs on global GDP growth, the estimates I’ve seen is anywhere from 0.5% to 1%, but you still have growth. So it’s hard to see we’re not going to see demand growth for the product in ’25 to ’26. Does that help?

Michael Blum: It does. Thank you. It does. Appreciate that. All right. That is all I have today. Thank you.

Operator: Thank you. Our next question comes from the line of Brandon Bingham of Scotiabank. Please go ahead, Brandon.

Brandon Bingham: Hi, good morning. Thanks for taking the question here. Would just like to maybe talk about the inorganic side of CapEx? And just in light of kind of where everything is trading now public and private if you see maybe a growing opportunity to capitalize on some of these defers prices? Or if maybe there’s kind of just a standoff between a bid-ask spread situation where sellers are more unwilling to transact at this level? Just any high-level thoughts you have around how that might factor into the strategy moving forward?

A.J. Teague: Brandon, this is Jim. My high level thought is, if it doesn’t fit what we have and we’re probably not going to be interested. If you look at our system, everything we’ve acquired are built, that’s what we already have, plus Randy always says price matters.

Brandon Bingham: Okay. Fair enough. And then maybe just a quick one. Looking at the slides, it looked like some of the movements on a quarter-over-quarter basis in segment margin were related to marketing. If you could just maybe provide some incremental detail around the moving pieces there?

Tug Hanley: Yes. On NGL marketing, specifically in the first quarter, we had additional LPG contracts step up at lower rates than the spot rates we achieved last year. So we had two to three cargoes a month. We were selling, for example, in the fourth quarter around $0.20 a gallon, and that spot margin has compressed in addition to additional term contracts stepping up.

A.J. Teague: Now on the flip side of that, we had a pretty good quarter natural gas marketing…

Tug Hanley: We did. On our natural gas marketing segment, we had two — really two bites of apple at winter volatility in January and February, which helped us out, and we’re also seeing high west to east spreads, Waha. So that was beneficial.

Brandon Bingham: Awesome, thanks guys.

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

Manav Gupta: Good morning. I wanted to ask you, can you give an update on the progress you are making at the Mentone West and Mentone West 2 get those projects online?

Graham Bacon: Yes, this is Graham. Both of those projects are coming online. Construction is going very well. We’re in early commissioning on the first Mentone West project and looking at those projects probably coming in a little bit ahead of schedule.

Manav Gupta: Perfect. You do have $7.6 billion of major capital projects under construction. $6 billion are expected to come online in this year. So help us understand how are the talks going to replenish their backlog. So once these projects do come online, how can you grow the backlog from here?

Randall Fowler: Yes, Manav, that’s where stepping out to 2026, that’s where our expectation is growth CapEx is $2 million, $2.5 million. And we’ve said that if you would, the unidentified wedge and that is only about $600 million or $700 million.

A.J. Teague: Plants.

Randall Fowler: Yes. So as Jim said, it’s two natural gas processing plants. And again, some of this is going to be dictated, the need for the plants, obviously is going to be dictated by the pace of producers and producer activity. But just even again, throwing out what Tony did earlier, even with if crude were to stay flat, crude production out of the Permian were to stay flat for two years, you’ve got increase of 1.5 Bcf a day of natural gas. That’s five processing plants at 300 million cubic feet of growth. So I think some of the pace of growth will be dictated by our producer customers here in the near term.

Manav Gupta: Thank you guys.

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

Keith Stanley: Hi, good morning. I wanted to ask the CapEx question from another angle, which is — are there any things on the drawing board that could potentially cause 2026 growth CapEx to be materially higher than $2 billion to $2.5 billion? Or is that very unlikely at this point?

A.J. Teague: It’s very unlikely.

Randall Fowler: Keith, if I could, one of the thing I would throw out here is I think we’re talking about level of CapEx relative to where CapEx has been in 2024 and 2025. And really, these are peak levels of growth CapEx for us. And really, you’ve got to go back to 2018 and 2019 when we were at that level of growth CapEx when we were bringing on new plants and really are not really new plants because those are more bite-sized. But when we were building more crude oil pipelines, NGL pipelines from Permian to Houston. And that’s to a degree what’s happening here exactly. We’ve got two projects that I can think of that probably are almost 50% of that $7.6 billion under construction. So again, we are at very elevated levels then.

And then when I think about some of those projects, the operational leverage that we have around that, that we can add a lot of capacity for instance in the heal, we can add a good bit of capacity for and call it, 400,000 barrels a day of capacity for probably $300 million. So the operational leverage that we have on expansions as a result of what we spent over the last couple of years really comes in and makes our growth CapEx in ’26 and what we envision in ’27 really to be able to come back down to a more normal run rate of 2 to 2.5.

A.J. Teague: And how many Natalie, how many processing plants that we built in the Permian in the last three, four years?

Natalie Gayden: More than I can count.

A.J. Teague: What do we got out there 20 trains?

Natalie Gayden: Well, we’re on #11 in the Delaware and #8 in the Midland.

A.J. Teague: A lot of what we’re doing is supply projects. And I think to Randy’s point, look at what Tug said earlier, we’re going to get 300,000 barrels a day for $400 million on our export facility. I think that’s a classic example of what our future looks like with our asset base.

Keith Stanley: That’s very helpful color. I didn’t realize the $400,000 a day on Bahia for $300 million. Second question, just one on the Crude segment, Q1 was lower. You called out lower deficiency fees. What asset is that on? And is the Q1 results more reflective of a run rate from here or not?

James Bany: Yes. Keith, this is Jay. As we think about the Q, our results this quarter on crude we had a couple of impacts. One was on lower sales volumes and a piece of that is also on sales margins. So just concentrating on the volume component this quarter versus first quarter of last year. Keep in mind that we had volumes on our Midland to ECHO 2 pipeline that was still flowing into Midland before we turn it over to NGLs and then a little bit on EFS. But to your question about how we think about that moving forward, we’re already into April. We’re seeing good results both on the volume and margin side. So I would — my view here, at least as April stands is we’re pushing past that.

A.J. Teague: You pipe out of Midland full…

James Bany: Yes. Pipes out of Midland are full today and looking forward to getting similar back into crude service here later this year.

A.J. Teague: Will it be full?

James Bany: And it will be full.

Keith Stanley: Thank you.

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

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

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