Enterprise Products Partners L.P. (NYSE:EPD) Q4 2024 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q4 2024 Earnings Call Transcript February 4, 2025

Enterprise Products Partners L.P. beats earnings expectations. Reported EPS is $0.74, expectations were $0.701.

Operator: Thank you for standing by, and welcome to Enterprise Products Partners L.P.’s Fourth Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand the call over to Libby Strait, Senior Director of Investor Relations. Please go ahead.

Libby Strait: Good morning, and welcome to the Enterprise Products Partners’ conference call to discuss fourth quarter 2024 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s General Partner, Jim Teague and Randy Fowler. Other members of our Senior Management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I’ll turn it over to, Jim.

Jim Teague: Thank you, Libby. I want to just go through some bullet points to highlight some of the things we achieved in 2024 and a few of the things we expect to do this year. First of all, 2024 EBITDA of $9.9 billion. Randy, it reminds me of a line in a Frankie Valli song, so close, so close, and yet so far. We had $7.8 billion of DCF. We had 1.7 times coverage, $3.2 billion of retained DCF. Chris, I thought that was a record, but it’s not, but it’s close, 12 financial records, 16 operational records. During 2024, we moved 12.9 million barrels of oil equivalent a day. In the fourth quarter, we moved 13.6 million barrels of oil equivalent per day. In the fourth quarter, we loaded out on for export 2.1 million barrels a day of liquid hydrocarbons against our commitments of 2.5 million barrels a day.

During ‘24 and early ‘25, we completed two processing plants in the Permian. We purchased Pinon, acquired the JV interest in our Midland to ECHO 1 crude oil pipeline and the JV interest in our 7th and 8th fractionators. For 2025, we’ll add two gas processing plants in the Permian. We’ll add the Bahia NGL pipeline, Frac 14, the first phase of our NGL export on the Neches River and expansions of our ethane and ethylene terminal at Morgan’s Point. That list almost needs to pause and take a breath. We get a lot of questions on SPOT. I want to give you a status report of where we are with SPOT. I believe that SPOT should be the poster child for the need for permit reform. By law, the record of this decisions should be issued 356 days, and we can have clock stoppages on top of that.

Frankly, I thought 356 was a typo, but it wasn’t. [Alto] (ph), it took over five years to get the SPOT license, including almost four years to get the record of decision and a year and a half to get the license to construct. Our initial application was 13,000 pages. I thought that was ridiculous, but by the time we completed the process, our final submission was over 30,000 pages. We addressed over 80,000 comments over two comment periods, predominantly from NGOs. One NGO’s comment was 60 pages long. We had to answer a ton of questions. One of my favorites was from a lady from Murat asking how we planned to mow the right of way. She was concerned that field mice would be protected from hawks. The process we went through due to federal bureaucracy pushed us beyond the drop dead date that allowed our anchor customer to opt out of their contract, which they did.

Granted, a lot has changed since we entered our SPOT application in January 2019. When we started that application, it was assumed that the majority of crude into exports would go to Asia on VLCCs. A lot of forecasters were predicting that 2024, the U.S. would be exporting between 7 million and 8 million barrels a day. Instead, we’re exporting around 4 million barrels a day. All of that with Russia invading Ukraine, which has resulted in the amount of crude oil export out of the U.S. to Europe to have doubled over 2 million barrels a day and that will grow more. That move to Europe can be done on an Aframax or Suezmax. Today, we have not gotten enough traction in commercializing SPOT, though we continue to promote SPOT as we are the only company with a license to construct.

We did a lot of research around cost, and our data shows that the cost to load on our SPOT project are always much lower than multi-reverse lighter VLCCs and have a lower all in cost than 50% of single-reverse lighter VLCCs and are competitive with the best 50% single-reverse lighter VLCCs. However, in order to build SPOT, we know what we need in volumes, fees and terms. We’re not going to establish a drop dead day, but if we can achieve these within a reasonable amount of time, we will move on. This is not a ‘build it and make it come’ project. Regardless, Enterprise remains laser focused on growing our exports. As I said earlier, we currently have expansion projects on the Neches River in Beaumont, at Morgan’s Point on the Ship Channel and at our main terminal on the Ship Channel.

We exported over 70 million barrels of hydrocarbons in December, everything from ethylene to crude oil and our goal is that we will export over 100 million barrels of hydrocarbons a month by 2027. We recently contracted with yet another ethane offtake customer in Asia, this one with a plant in Vietnam. And, we were working with numerous other customers around the world on hydrocarbon supply agreements. The last 24 months, we’ve visited over 25 cities to sell U.S. hydrocarbons, some we visited multiple times. I know I’ve been in Mumbai at least four times. Someone from enterprise is almost always in Asia or Europe, and no one even comes close to having the history and experience that we have. Think about it, we built our first LPG import terminal in 1983 and our first export terminal in 1999.

We’ve been active in the international market for over 40 years. On a personal note, while I was at Dale, the first cargo of imported propane that I ever purchased went through the Enterprise terminal. And in total, our term commitments at our docks today exceed 2.5 million barrels a day, and that’s hydrocarbons, ethylene to crude oil. We forced the way to reach our goal of 100 million barrels a month. And with that, I’ll turn it over to Randy.

W. Randall Fowler: Thank you, Jim, and good morning to everyone on the call. Starting with fourth quarter income segment items. Net income attributable to common unitholders for the fourth quarter of 2024 was $1.6 billion or $0.74 per common unit on a fully diluted basis. This is a 3% increase compared to $1.6 billion or $0.72 per unit for the same quarter in 2023. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital, increased 4% to $2.3 billion for the fourth quarter. This compares to $2.2 billion for the fourth quarter of 2023. We declared a distribution of $0.535 per common unit for the fourth quarter of 2024, which is a 4% increase over the distribution declared for the fourth quarter of 2023.

The distribution will be paid February 4 to common unitholders of record as of the close of business on January 31. In the fourth quarter, the partnership purchased approximately 2.1 million common units off the open market for $63 million. Total purchases for 2024 were $219 million or approximately 7.6 million Enterprise common units, bringing total purchases under our buyback program to approximately $1.1 billion. In addition to buybacks, our Distribution Reinvestment Plan and Employee Unit Purchase Plan purchased a combined 6.5 million common units on the open market or $188 million in 2024. This includes 1.6 million common units for $48 million during the fourth quarter of 2024. Of note, almost half of our employees participate in the Employee Unit Purchase Plan.

For 2024, Enterprise paid out approximately $4.6 billion in cash distributions to limited partners, Combined with the $219 million of common unit repurchases over the same period, Enterprise’s total capital return of $4.8 billion resulted in a payout ratio of 55%. Since our IPO in 1998, we have returned approximately $56 billion to unitholders in the form of distributions and buybacks, while building one of the largest energy infrastructure networks in North America. Total capital investments in the fourth quarter of 2024 were $2 billion which includes $946 million for growth capital projects, $949 million for the acquisition of Pinon Midstream and $113 million of sustaining capital expenditures. Capital investments for the full-year of 2024 were $5.5 billion which includes $3.9 billion for organic growth capital projects, the $945 million for Pinon and $667 million for sustained capital expenditures.

As mentioned in last quarter’s earnings call, we have received noteworthy support from our producer customers following the Pinon acquisition. And for that reason, we are fine tuning our 2025 estimated growth capital expenditures range to $4 billion to $4.5 billion to include new opportunities in sour gas gathering and treating projects as well as additional natural gas gathering and compression projects in the Delaware Basin. Our expected range of growth capital expenditures for 2026 remains unchanged at $2 billion to 2.5 billion. We expect 2025 sustaining capital expenditures will be approximately $525 million which includes a planned turnaround at our Octane Enhancement plant. Moving to capitalization. Our total debt principal outstanding was approximately $32.2 billion as of December 31, 2024.

Assuming the final maturity date for 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 98% of our debt was fixed rate. Our consolidated liquidity was approximately $4.8 billion at the end of the year, including availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA was $2.6 billion for the fourth quarter and, as Jim mentioned, $9.9 billion for 2024. We ended the year with a consolidated leverage ratio of 3.1 times 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 three times, plus or minus a quarter, so in the range of 2.75 to 3.25.

And with that, Libby, I think we can open up for questions.

Libby Strait: Thank you, Randy. Operator, we are ready to open up the call for questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Our first question comes from the line of Spiro Dounis of Citi. Your question please, Spiro.

Spiro Dounis: Thanks, operator. Good morning, everybody. First question, maybe just go to the outlook for 2025. I know you guys don’t provide guidance, but we just get results the way you close the year, it seemed like it was pretty strong. So just curious, two part question here, any reason that that’s not a good baseline to sort of run rate as we think about 2025? And then if you could, maybe just outline some of the bigger drivers of growth this year?

W. Randall Fowler: Yes. Spiro, I’ll go back to what we said on our Investor Day call a year ago that really we think near-term, we’ve got the potential for call it mid-single-digit cash flow growth over the near to intermediate term. And, I think that’s sort of our view going into 2025. Jim mentioned the number of projects that we have coming on. Most of them, the larger ones for sure come on later in the year. So, we’ll see some of that growth on the second half of the year. But, 2025 is setting up a strong year, especially when you come in and just look at industry fundamentals.

Spiro Dounis: Great. That’s helpful. Thanks, Randy. Second question, just to go back to SPOT. So, I know you’re not providing a drop dead date to get that facility FID, but two parts here once again. Does it seem less likely or unlikely at this point that a 2025 FID is possible? And, you also mentioned being the only one licensed. Just curious, can you just talk about license expiration timing, what that looks like and what it would take to renew it if you don’t FID, let’s call it, within two years?

W. Randall Fowler: Yes. I think we’ve renewed one permit, Bob.

Robert D. Sanders: Yes. We renewed the air permit, right, Graham, to 2028?

Graham W. Bacon: Yes. We’re not that worried about renewing permits if we need to.

Spiro Dounis: Okay. And does it seem like a ‘25 FID based on customer feedback at this point, maybe less likely?

Graham W. Bacon: I’m not going to admit to that.

Spiro Dounis: Okay. I try to get you. All good. I appreciate the color here. I’ll leave it there. Thank you, guys.

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

Theresa Chen: Thank you for taking my questions. Follow-up to the cadence of earnings growth in 2025, can you help us think about, the path to recovery for the petchem segment? What are the puts and takes there? And as far as operations and utilization goes for the larger the newer projects, how is that going at this point?

W. Randall Fowler: I think we’ve got to run the PDHs. That’s one thing from our perspective, and we will. From a petrochemical market perspective, I don’t think Chris is here, but, there he is. But, it looks pretty bad right now, doesn’t it, Chris?

Christopher F. D’Anna: Yes, I think what we’re hearing from most of our customers domestically is they’re seeing moderate improvement from last year and they’re not expecting anything much bigger. Globally, the market is oversupplied. So that’s the headwind there.

Jim Teague: Who is it, Theresa? Yes, Theresa, this is Jim. What I see is we are signing, we just signed recently within the last two or three weeks, Tug, a contract with the Southeast Asian petrochemical company for a sizable ethane contract. I think we’ll be back in Southeast Asia for another one. The other thing that I wouldn’t be surprised at is ethane feedstock to crackers in other parts of the world is advantage to naphtha. It wouldn’t surprise me and help me, Chris, to see crackers shut down in other parts of the world and ethylene exports beginning to fill that void.

Christopher F. D’Anna: Yes, I mean, we’re already seeing some of that. And, that helps not only our ethylene, but it also helps the propylene markets because those naphtha crackers in the rest of the world also do make a lot of propylene. So, that will help rationalization.

Theresa Chen: Interesting. Thank you so much. And then on the LPG side, following a competitor announcement of a new export project in Galveston Bay today, how do you think about the potential change to export economics to competitive economics within the region?

Brent B. Secrest: Theresa, this is Brent. If you see capacity come online and there’s industry capacity come online this year, we’ll have some in the back half of this year as well, and then a larger expansion for next year. But right now the dock FOB values are pretty healthy. Obviously, as this capacity comes online, this will start to become eroded. When you look at our capital for expansion, it’s less than a third of what a greenfield expansion is. So, we’ll see. I didn’t listen to the call, but, that’s in terms of when we run the numbers, that’s a little bit of a challenging project.

Jim Teague: Theresa, this is Jim. We’re not going to give up our LPG export franchise. We’ll do things more favorable to our customers than anyone.

Theresa Chen: Understood. Nor would I expect you to give anything up, Jim. Thank you.

Operator: Thank you. Our next question comes from the line of Jean Ann Salisbury of BofA. Your question please, Jean Ann.

Jean Ann Salisbury: Hi, good morning. Can you talk about how you see the size of the eventual prize for being able to handle sour gas in the Permian? Do you expect sour gas to grow much faster as a share? Or is it mainly a strategy to be able to have a broader customer offering and get more customers?

Natalie K. Gayden: Hey, Jean Ann. This is Natalie. I don’t think anything’s going to be fast. However, we are permitting a third AGI well, or we’re in the front of it. We’re also expanding the two AGI wells there. We’ll build our fourth train, and then we have our eyes on the fifth train. So, I don’t know how quickly, but I think we’ll, it does give us a new asset base to be able to expand integrated value chain to the upstream side.

Jean Ann Salisbury: Okay. That makes sense. And then as a follow-up, can you just kind of talk about how you expect your flex NGL exports to ramp as they come online? Roughly how much in ethane versus propane service to start?

Tug Hanley: Hi, Jean Ann. This is Tug Hanley here. On the ethane side, so we’re fully contracted on our base capacity of 540,000 barrels a day. We’re in the process, we’ve identified low cost expansion debottlenecking projects, and we’re well into contracting that additional capacity. So, if you think about how that’s going to play out, we’re waiting on the [DLUCs] (ph), the ships get delivered, as those ships continue to get delivered and ramp our ethane exports at our Neches River terminal, that timing coincides with our Ship Channel expansion, around 300,000 barrels a day. So long-term, we expect it to be ethane at Neches and we’ll have our Ship Channel expansion to pack for that. And, we’re continuing to see robust demand on ethane exports. And as Brent alluded to, we have great brownfield expansion opportunities across all three of our export terminals. And then when our expansion comes on for LPGs for 85% contracted on LPGs.

Jean Ann Salisbury: Well, great. That’s great color. I’ll leave it there. Thank you.

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

Michael Blum: Thank you. Good morning, everyone. So, appreciate the slide and the comments on capital allocation. I wanted to ask you about buybacks specifically. Just if you’re thinking about buybacks any differently as a component of capital return, should we expect the cadence we’ve seen in the last couple of years should be consistent going forward or any change there?

W. Randall Fowler: Yes, Michael, good morning. Yes, we sort of come in and carry that thing as far as the potential for cash flow growth to be mid-single-digits. Jim mentioned earlier that we had $3.2 billion of excess distributable cash flow in 2024. And, if you take that forward a couple of years to 2026, that probably puts you in the neighborhood of $3.5 billion, $3.6 billion of excess DCF. And, then if we’re up at the upper end of our growth CapEx range of $2.5 billion that leaves you about $1 billion, $1.1 billion of excess DCF after fully funding your growth CapEx with excess DCF, that’s left over for buybacks and debt retirement. Our leverage target, again, is the range 2.75 to 3.25. Our midpoint is 3. That’s about where our leverage is today. And so, I think we’ll have a lot more flexibility to do buybacks and maybe a little bit of debt retirement once we get out to 2026.

Michael Blum: Thanks for that, Randy. Appreciate it. And then, I just want to ask about as we head here into 2025, the M&A landscape, how active what’s out there for you and do you expect this to be an active year for Enterprise? Thanks.

W. Randall Fowler: Yes. 2024 was a pretty active year and we’ve looked at virtually every asset package that came across. And again, Pinon was the most attractive to us, and we executed on that. We do see some additional asset packages. We think we’ll see some later in the year. And we’ll take a hard look at those and see what fits well in our system. Public company M&A, little bit harder to do, especially if your goal is to drive cash flow per share, cash flow per unit growth. Public M&A can be a little bit on the problematic side. We don’t see as much value as we do with asset purchases, but we’ll take a look at both.

Michael Blum: Thank you.

Operator: Thank you. Our next question comes from the line of Neal Dingmann of Truist Securities. Your question please, Neal.

Neal Dingmann: Good morning. Thanks for the time. My first question guys just on GOM. I’m just wondering, looks like that the processing spread and others have stayed or I guess they were pretty stable for the remainder of last year. Are you expecting more of that this year? Or maybe just talk about the activity there.

W. Randall Fowler: I mean, I think in terms of the forward curve, Neil, I think we think that spread is going to be there. It’s probably more when you look at Waha, it’s a function of Waha gas price. I would probably think ethane is fairly stable for this year. It’s probably going to escalate a little bit, but in terms of the processing spread in our system and the recovery of our thing is probably more of a function of the Waha gas price.

Neal Dingmann: Got it. Okay. And then just one forward, love to hear just on prospects of now where we sit on the macro side. I’m just wondering based on how you all are looking at it. You’ve talked about M&A now today. Is that predicated on what you’re thinking on the macro on both the oil and the gas side? I just wanted to hear kind of what you’re thinking for the remainder of the year on the macro commodity side.

Jim Teague: Neal, would you mind repeating that?

Neal Dingmann: Yes. Randy, you laid out kind of I know you guys were active on the M&A side. I’m just wondering, is this predicated? I’d love to hear you guys always give a pretty good forecast on what you’re thinking the commodity wise, both I’d say gas NGLs and oil. And just wondering, are you expecting a bit of a ramp, commodity wise for remainder of the year? And I guess I’m asking is M&A predicated on this?

Jim Teague: I don’t know if M&A is predicated on it, but you’re talking about ramping price or ramping production?

Neal Dingmann: Price. Jim, just trying to figure out what you all are thinking for pricing the remainder of the year.

Jim Teague: For price, if we start with oil, it’s been range bound, not at really bad prices quite frankly, it’s really been quite range bound. And not just for the last year, but even longer than that. Our belief is that the EPIC Plus continues to be very focused on that. They don’t want prices too high and they don’t want them too low. I don’t know what changes that landscape. Right now, there’s a lot of discussion about will we move into a, for lack of a better term, “drill baby drill” scenario. And all signs are that we will not, that it will be, call it slow and steady from very large numbers already. That said, we continue to see that rich natural gas production just sticking to the Permian, continues to exceed our expectations.

And we will be reforecasting and publishing a new forecast probably sometime in the second quarter. We’re working on it now. And I’ll say, Neal, I wouldn’t be surprised if our natural gas liquids forecast in the Permian specifically is not up again from the prior one, but give us some time to work through it. And then Brent’s pointed to the natural gas equation. It’s somewhat weather related. Waha is very much what pipes can you count on running related. That matters a lot to us. So, there you have that. Last but not least, we’re pretty constructive on natural gas long term just because of what we see from the demand standpoint for LNG and for power.

Neal Dingmann: Okay.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet of J.P. Morgan Securities. Please go ahead, Jeremy.

Jeremy Tonet : Hi. Good morning.

Libby Strait: Good morning.

Jeremy Tonet : Just want to start off, I guess, any updated thoughts out of DC? Just wondering, in the Trump administration, imagine permitting might be easier, also talking about energy emergency and how that could impact permitting overall. Just wondering what you hear coming out of DC, anything different and could that impact, I guess, your growth strategy going forward?

Jim Teague: For me, reform would be nice, but I got to see it to believe it, frankly.

Jeremy Tonet : Got it. Anything else out of DC on your radar right now or just kind of business as usual?

W. Randall Fowler: Jeremy, again, on the permit reform, it just seems like that’s going to take some time and pretty involved. The other thing is just what the administration is looking to do as far as from a tax package and extend some of these provisions at sunset at the end of 2025 to get extended. So, thus far, really no surprises from where we were frankly right after the election. It seems like the administration and Congress were following through with what they were talking about during the election cycle and right after the election.

Jim Teague: Jeremy, the lack of permit reform seems to make what we have in the ground a heck of a lot more valuable.

Jeremy Tonet : Got it. Yes. No, absolutely. And just want to touch base real quick on the PDH facilities 1 and 2. Where are the current, I guess, operating run rates and where do you see them going over the course of ‘25 and kind of hitting a normalized level?

Jim Teague: You want to hit it, Graham?

Graham W. Bacon: Yes, Jim. This is Graham. Right now, we’re looking to increase the run rates of the PDHs. Obviously, they haven’t met our expectations. Currently, we’re working through a mechanical issue on PDH-1, but that coming out of our turnaround last year, it really ran pretty well. We had a minor blip we’re working through right now, but expect to get a sustained run rate there. PDH-2, we’re working through a design issue with our licensor that has the rates currently limited. We expect to get that resolved and long term target is to have those operating in the upper 90% of utilization.

Jeremy Tonet : Okay, got it. 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. Thanks for the time. I want to stay on some of the policy stuff. We’ve obviously seen a lot of different headlines on the tariff front, but we had some kind of retaliatory tariffs from China overnight, I guess. So far from China, they’re not on the NGL front, but I guess I’d just be curious to hear your takes overall on any of these energy tariffs, how you think about that in the context of your export footprint? Thank you.

Jim Teague: China imports, we don’t have I think we have one contract with one Chinese company on propane. Is that right?

W. Randall Fowler: That’s right.

Jim Teague: Yes. But a lot of our propane out of the US goes to China for their PDH plant stub. They’ve got a lot of PDH plants, and they don’t have any propane. So, I don’t see it affecting that. We have ethane contracts with two customers. And those crackers can only use ethane type. Right. So, they don’t have any ethane. So, from an NGL perspective, I’m not worried. Now, that’s most of what we have that got on the LPG that goes to China goes through trading companies. We’re getting interest in places, like Southeast Asia, where we’re going to have two contracts before it’s all said and done. And we’re expanding another contract in Asia by 40,000 barrels a day. And then we have a huge contract in Europe. So, Doug is a little modest, when he says 540,000. I think where we will end up on ethane is 600,000. And he’s pointing higher. And then I think on 85% LPG, I think we’ll contract that out before it’s offset and done.

John MacKay: I appreciate all that. Thank you. Maybe just a follow-up. I wanted to ask about the NGL pipeline side volume and if we’re just looking year-over-year, I know there’s always a little bit of noise, but volumes were up a lot. Margin itself wasn’t up a ton, you guys called out some higher costs. I’d just be curious your take on kind of NGL pipe margins going from here, how to think about those that extra OpEx side. And then maybe comment on this in the context of broader NGL pipe competition? Thanks.

Justin M. Kleiderer: Yes, it’s Justin. A few things going on the volume side, so let’s cover that. Significant walk up volume, which incorporates a lot of our purity movements along with the trajectory that we see on just overall Y Grade growth. So, you’re seeing some a big quarterly step up as a function of some of those month-to-month movements on the purity side, but we are continuing to see that nice ramp of Y grade volumes trending in the right direction. When you look at the GOM side, it’s one thing to note that while Permian Y Grade rates stay in the reinvestment economic range, as we build out Bahia, a lot of what changes associated to Rockies flows and those Rockies tariffs are significantly higher. And so sometimes that can when you look at this volume and GOM perspective can make the fee may otherwise skewed a fee.

So, changes in our Rockies flows can sometimes make the per unit GOM otherwise more skewed than what you’d anticipate. So, all in all though, the growth that we’re seeing in the Permian continues to support reinvestment economics on the wide rate side.

John MacKay: Sorry, just on the context of kind of competition from new pipes coming in, how are you feeling about that?

Justin M. Kleiderer: Yes. We still like our platform. We’re still growing our GMP footprint. I’d say, when you look at in service Bahia in the fourth quarter, we’re quickly right behind that going to convert Seminole back to crude service. We’ve guided to that in prior calls. And so when you take that into account going into 2026, we’d expect Bahia to be 60% full with more coming behind it as we continue to ramp. So, we still feel like our platform gives us a pathway to being full over the coming years.

John MacKay: All right. That’s clear. Appreciate the time. Thanks so much.

Operator: Thank you. Our next question comes from the line of A.J. O’Donnell of TPH. Your question please, A.J.

A.J. O’Donnell: Yes. Thanks. Good morning, everyone. I was just hoping maybe we could start on, NGL marketing. There were some notable strength there quarter-over-quarter. I was just wondering if you could expand a little bit on the prospects for 2025, in light of commodity price movements and maybe the potential to offset any lower margins from natural gas marketing as a result of higher Waha spreads?

W. Randall Fowler: Yes, I mean, it’s a function, we had some higher FOB values across our dock in the LPG side, but the bottom line is volatility presents itself, and the market will be there to monetize it and we continue to do that, and those opportunities continue to present themselves.

A.J. O’Donnell: Okay. Thanks for that. Maybe one more, you know, on data centers. We saw the Stargate announcement and I’m just curious. I know you guys have some intrastate lines in the area. Is there any capacity on your Texas intrastate system to be able to feed that project?

Angie M. Murray: We’ve pulled out the capacity on both of our — it just depends on where the project is. Just to give you some perspective of how much data center demand is out there, we’ve got probably 20 data center projects in the queue on the Texas side. We placed over 2 bcf a day of demand. We believe only probably 15% of those projects are showing signs of progress. On the power plant side, which may see data centers, if you believe it’s just power from those, we’re looking at probably 15 potential projects around 1.2 bcf a day, and maybe 50% of those are real. So, depends on where the data center project is and it stems all the way from Dallas to San Antonio. So, if our lines are closed, we’re going to take the opportunity to serve the data center where it makes sense.

A.J. O’Donnell: Okay. Great. Thank you.

Operator: Thank you. Our next question comes from the line of Brandon Bingham of Scotiabank. Your question, please, Brandon.

Brandon Bingham: Hi. Thanks for taking the questions. If we could go back to the volumes side and the volumes outperformance this quarter, just wondering how sticky those volumes are and kind of how you see that progressing throughout 2025?

Jim Teague: Yes. Brandon, I think if you come in, I mean, that’s really just the growth at the wellhead, especially the growth at the Permian and really the benefit of a value chain. So, it’s flowing into our gas processing plants, those liquids out of the processing plants flow into our downstream pipelines through our fractionators all the way to the dock. So, what is that thing? Wellhead to water? I think that’s pretty much what you’re seeing across our system.

Brandon Bingham: Awesome. Thank you. And then if we could just quickly go back to the petchem side. And on the margin front, you guys had previously discussed the PDH plants contributing, I think it was roughly $200 million a year in EBITDA whenever they’re running as they should. Could you just talk about what margins were baked into that $200 million number and how those compare to what you’re currently seeing?

Jim Teague: The margins haven’t changed because it’s a formulaic price. Isn’t that right, Chris?

Christopher F. D’Anna: Yes. The way our PDH contracts are set up, they’re all toll based, so it’s cost plus. So, it’s really just a function of utilization rates.

W. Randall Fowler: And really what we were talking about was, I think where we looked at where earnings were in 2024, we see the potential for the PDHs to contribute an incremental $200 million in 2025.

Brandon Bingham: Got it. Okay. Thank you.

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

Manav Gupta: Good morning. My quick question here is any update on the Morgan Point Flex expansion that you can provide?

W. Randall Fowler: As far as an update on where we are with the Morgan’s Point Flex frame?

Manav Gupta: Yes. Yes.

Christopher F. D’Anna: This is Chris D’Anna. We finished the construction at the end of December of last year, so it’s in service and ready to serve. Today, it’s mostly being filled for ethane because there’s a lot of both planned and unplanned outages on the cracker side that’s limiting the arb for ethylene, and the ethane opportunities are there.

Manav Gupta: Perfect. And the second one is more on the Haynesville side. Do you still see that as a growth basin? And are you looking at growth opportunities coming out of the Haynesville basin?

Angie M. Murray: Haynesville it’s a growing basin, although it rig counts wouldn’t show that to be true. We have seen some growth in our portfolio, and this is from new acreage developments that producers are hitting. However, I don’t know that the Haynesville has truly grown over the last year. I would say the opposite. Over the next year, I think we do see some growth potential. But again, gas price drives that story.

Manav Gupta: Thank you so much.

Christopher F. D’Anna: We’ll be updating our Haynesville forecast at least for its potential when we update our forecast in the second quarter.

Jim Teague: What it’s doing and what its potential is, is key in it.

Christopher F. D’Anna: That’s what it is. That’s why I use the word potential.

Manav Gupta: 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, all investors, 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.