Enterprise Products Partners Q1 2026 Earnings Call - Geopolitical Volatility Drives Record Volumes and Outsized Spreads

AJ O’Donnell, Analyst, TPH&Co.5: I would now like to hand the call over to Joseph Theriac, Vice President of Finance and Investor Relations. Please go ahead.

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: Thanks, Lateef. Good morning, 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, A. J. Teague and W. Randall 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 and 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, Co-Chief Executive Officer, Enterprise Products Partners: Thank you, Joe. We got off to a very strong start this year. 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 1.8 times 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 three Permian natural gas processing plants, continued to ramp throughout the quarter. In fact, Frac 14 was full on day one. The gas plants were essentially full by mid-quarter. If you look at Bahia and Chinook 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 Mentone West II in the Delaware Basin during the first quarter, we set a new record for gas processing plant inlet volumes. We processed 8.3 billion cubic feet per day of natural gas. That was up 7% from last year. We fractionated 1.9 million barrels per day of NGLs. That was up 16%. We loaded 2.3 million barrels per day of hydrocarbons at our docks, up 15%. We transported 14.2 million barrels of oil equivalent per day, up 7%. In total, we set 12 new volumetric records for the first quarter. Those results speak to both the scale of our system and the demand we’re seeing across the markets we serve.

On the market side, commodity prices were volatile throughout most of the quarter. We tend to embrace volatility. In January, Winter Storm Fionn 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 sharp 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. 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 Strait 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. One week before the start of the war in Iran, ethane to ethylene cracking margins were about $0.07 a pound. Today, they’re at $0.23. The ethylene to polyethylene spread was $0.20 per pound. Now it’s over $0.45. It’s no wonder why my former employer’s 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 we hear 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. We see this strong demand continue through the remainder of 2026 and maybe into 2027. The demand pool is showing up very, 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. 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 docks. 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 Strait of Hormuz. Depending on the industry expert you ask, anywhere from 12 to 15 million barrels a day of crude oil, refined products, LPG, and petrochemical supplies are constrained. That is almost half a billion barrels of hydrocarbon supplies off the market every month. Shipping and geopolitical commentators estimate that the earliest the strait could reopen for normal operations, including vessel repositioning, is July. That does not account for the time required to repair onshore production and refining facilities damaged in the war.

Until global supplies and inventories return 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 as an avenue to improve the U.S. trade balance and add greater resilience and 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 safely, serving our customers reliably, allocating capital with discipline, and creating long-term value for our investors. With that, I’ll turn it over to Randy.

Brandon Bingham, Analyst, Scotiabank0: Thank you, Jim. Good morning, everyone. Starting with the income statement items, net income attributable to common unit holders 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 May 14th to common unit holders of record as of close of business on April 30th. 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 unit holders. The partnership purchased 3.1 million common units off 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 received 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-$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-$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 had the potential to be in the $1 billion area. Even though our estimate of growth capital expenditures for 2026 has increased by $300 million as a result of investments in two new natural gas processing plants in the Permian, we still believe discretionary cash flow for 2026 has the potential to be in the billion-dollar 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 split would be approximately 50%-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 ebbed.

Similarly, in periods when there are significant price dislocations in equity prices, we may elect to pull cash forward, earmarked for 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 31st, 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 31st, our consolidated liquidity was approximately $3.3 billion, including availability under 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 3.2 times 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 investment in the large-scale projects that we recently brought into service, such as the Bahia NGL Pipeline, Neches River Terminal, and Frac 14, 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 has yet to flow into our 12-month trailing EBITDA numbers. Our overall leverage target remains at 3 times ±0.25 times or 2.75 to 3.25. With that, Joe, I think we can open it up for questions.

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: Thanks, Randy. Latif, we are ready to open the call for questions.

AJ O’Donnell, Analyst, TPH&Co.5: Our first question comes from the line of Theresa Chen of Barclays. Your line is open, Theresa.

AJ O’Donnell, Analyst, TPH&Co.8: Good morning. 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 docks today? Specifically, how much capacity is tied to contracts with near-term expirations that could be recontracted at higher rates? Longer term, how much incremental brownfield expansion capability do you have across your export assets?

AJ O’Donnell, Analyst, TPH&Co.9: Hi, Theresa. This is Tyler Cott. I’ll speak to the NGL export specifically. I think we’ve said before, our NGL export docks are contracted around the range of 90%. On LPG, those contracts go through the end of this decade. On ethane, they extend, you know, 10-20 years, depending on contracts, so lengthy duration. We have 10% available for spot capacity in the near term, but long term, we’re significantly contracted.

AJ O’Donnell, Analyst, TPH&Co.8: Okay. On the LPG side in particular, given the recent strength in LPG export ARBs, alongside the commissioning timeline for Phase 2 of the Neches River expansion, can you talk about the incremental earnings uplift or cash uplift from spot cargoes in the interim? Related to this, when do you expect Phase 2 to officially enter service to support your term commitments with customers?

AJ O’Donnell, Analyst, TPH&Co.9: Sure. This is Tyler Cott again. Our operations team has done a fantastic job expediting a bit the commissioning of Neches River Terminal. We’re still in the process of commissioning it. We began in the 2nd half of April. 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 is we have a significant amount of flexibility. Our spot business will be dictated across different products in terms of what the market needs at a given time.

Brandon Bingham, Analyst, Scotiabank0: Jay?

Jay Bany, Senior Management, Enterprise Products Partners: Yeah. Hey, Theresa, this is Jay Bany. Just on the crude front of that, we’ve got a pretty wide mix of contract structures, so contracts that last through 2028 and 2029. Similar for 2026, we have about 10% of open capacity. Yes, I think we’re having good conversations about 2027.

AJ O’Donnell, Analyst, TPH&Co.8: Thank you.

Brandon Bingham, Analyst, Scotiabank0: Thank you. Our next question comes from the line of Spiro Dounis of Citi. Your line is open, Spiro.

AJ O’Donnell, Analyst, TPH&Co.7: Thanks, operator. Good morning, team. Wanted to get back to the growth outlook really quickly. Jim, you sound incrementally more positive than when we last caught up. Obviously, a lot has changed. Randy, you seem to indicate that your operating cash flow is gonna at least sort of mirror the increase in CapEx to keep that DCF free cash flow kind of stable. You know, curious if you just give us an update on the sort of 3% growth you guys were talking about for 2026 and the 10% growth you were talking about for 2027 on the last call. As you answer that question, just curious if these two new processing plants are additive to that 2027 outlook.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Spiro, this is Jim. I think I said modest in 2026 and 10% in 2027. I think we’ll beat modest.

AJ O’Donnell, Analyst, TPH&Co.7: Randy, anything about. Sorry, go ahead.

Brandon Bingham, Analyst, Scotiabank0: Yeah. Yeah, 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. You know, again, it’s sort of hard to come in and look at 2026 because again, just what’s the duration of these commodity prices gonna be and the duration of spread. Really shaping up to be a much stronger year than what we expected. Again, cause we were really coming in and not expecting much benefit at all from commodity or spread, and really we’re relying on our fee-based businesses. 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. At the endpoint is 2026 looks to be a much more favorable year than when we first started. We commercial guys team did a great job in underwriting 2 more natural gas processing plants in the Permian, which really, you know, they will come on during 2027. We really did not have those baked into our 2027 numbers at the time, so that would be additive.

From the same token, you know, 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 two new plants.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Yeah. Spiro, 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.

AJ O’Donnell, Analyst, TPH&Co.7: Yeah. That’s actually a good segue to the second question. Jim, you also talked about embracing volatility. I know we go back a few years ago, you used to sort of talk about this sort of $500 million or so of outsized spread gains you guys would sort of find in any given year. That’s been absent for about maybe the last two years or so. Just curious, it sounds like that’s back. You know, I don’t wanna put too fine a number on it, but in the environment you’re seeing now, do you think you see a return to that $500 million? You know, what parts of the market do you see that from? Obviously, export being a big one.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: I don’t know if it’s gonna be $500 million, $600 million, or $700 million, frankly. I do expect that we’re gonna have what you call outsized spreads, frankly. Typically, we have it every year, we just don’t know which spread it’ll be. Last year was pretty benign and unusual for us. As to what specifically it might be, I’ll throw it to Tug.

AJ O’Donnell, Analyst, TPH&Co.9: Yeah. This is Tug. I’ll just add, I mean, this first quarter, we had some outsized spreads on natural gas. Winter Storm Fionn presented some opportunities. Largely the spreads that we’ve seen post-Iranian conflict, those will come second quarter.

AJ O’Donnell, Analyst, TPH&Co.7: Great. Helpful. Helpful color, guys. I’ll leave it there. Thank you.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Jean Ann Salisbury of BofA. Your line is open, Gene.

Jean Ann Salisbury, Analyst, Bank of America: Hi, good morning. We talked about this a little bit at the dinner, Tug, but it seems like international crackers that are running ethane 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 ethane that could drive the next leg of ethane demand?

AJ O’Donnell, Analyst, TPH&Co.3: Hi, Jean. This is Tug. Yes, they were happy prior to the conflict and they’re even happier now. I will say that the interest in 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.

Jean Ann Salisbury, Analyst, Bank of America: That’s helpful. I guess as a follow-up to that question, what’s kind of the timeline 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?

AJ O’Donnell, Analyst, TPH&Co.3: That’s, that’s probably-

Jim, Co-Chief Executive Officer, Enterprise Products Partners: It’s not overnight, Jeanann.

AJ O’Donnell, Analyst, TPH&Co.3: Yeah.

I think your couple of years is probably in the ballpark.

Jean Ann Salisbury, Analyst, Bank of America: All right. Thank you. I’ll leave it there.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Michael Blum of Wells Fargo. Your line is open, Michael.

AJ O’Donnell, Analyst, TPH&Co.2: Thanks. Good morning, everyone. You know, at dinner, a few weeks ago, you didn’t, you didn’t really think you’d see any permanent shifts in where global buyers are gonna source their hydrocarbons. I thought maybe they’d shift more to the U.S., but you seem to think that that wouldn’t happen. Curious just if you’ve had any change in your, in your thinking there. On a similar vein, I think at the time you didn’t really think we’d see any reaction or from the U.S. producers, and I’m curious if you still think that’s the case.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Take the second one first, Jay and Natalie, what reaction by U.S. producers?

AJ O’Donnell, Analyst, TPH&Co.4: This is Natalie Gayden. I’d say, and Jay can chime in here, I don’t know that U.S. producers have done much different. It seems to me that they’re staying pretty disciplined. Sure, we see some movement and rig activity to different maybe producing zones or maybe different areas of their acreage if they have discretionary acreage. Other than that, I’d say they’re keeping discipline.

Jay Bany, Senior Management, Enterprise Products Partners: Yeah. 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 three months, that could just be anecdotal.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: As to the first question, Jean Ann, you know, a supply disruption like we have changes a lot of things. We’re seeing interest from countries, Tug, like India. You know, it’s a funny thing. We’re geographically challenged when it comes to LPG in India. The question will be: When this is all over and everything returns to normal, do they still wanna lift U.S. LPG when the AG is so close to them? Right now, they’re showing a lot of interest.

AJ O’Donnell, Analyst, TPH&Co.2: Okay. Thanks for that. The second question is just on capital allocation. Randy, 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, would you maintain that 50%-60% allocation to buybacks versus debt pay down? If that $1 billion turned into $1.5 billion, for example, would the incremental above plan just go to buyback since your leverage is already within the target? Thanks.

Brandon Bingham, Analyst, Scotiabank0: Michael, I like the way you’re thinking this morning. Michael, I think we would still in the near term, when we think about 2026, we’d probably still maintain that 50%-60% split. You know, 2027 could be a different story, I think 2026, still probably maintain that split.

AJ O’Donnell, Analyst, TPH&Co.2: Thank you.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Brandon Bingham of Scotiabank. Please go ahead, Brandon.

Brandon Bingham, Analyst, Scotiabank: Hey, good morning. Thanks for taking the questions. Just thinking about the two new plant announcements in the Permian, and I know it hasn’t even really been a month since the macro update. Just curious what you think the go-forward cadence should be for Permian processing capacity. I believe previously you guys were around one or two a year with the thought process. Do you think we’re moving more to a two-plus environment or just, you know, how should we think about that moving forward?

AJ O’Donnell, Analyst, TPH&Co.4: This is Natalie Gayden. I think we’re probably trending closer to two. Obviously that depends on how GORs shape up. Corey’s showing me that GORs are increasing. That is definitely true. I’d say we’re trending more to two per year.

Brandon Bingham, Analyst, Scotiabank: Okay, great. Thank you. 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?

Jay Bany, Senior Management, Enterprise Products Partners: Brandon, this is Jay again. We’ve seen volumes leave our dock. I mean, you go back to first quarter last year, I think for fourth quarter, we were up 70,000 barrels a day on exports. Add that to the first quarter, that’s another 70 with the SPR barrels. Looking for second quarter, I mean, we could be well over 1 million barrels a day.

Brandon Bingham, Analyst, Scotiabank: Okay, great. Thanks.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Manav Gupta of UBS. Please go ahead, Manav.

AJ O’Donnell, Analyst, TPH&Co.1: Good morning. Congrats on the good results. I just wanted to quickly focus on slide 17. It looks like PDH units are operating much better based on that slide, I think you did do some kind of turnaround on the PDH 2, and it’s been operating better after that. Can you speak to those dynamics, please?

Brandon Bingham, Analyst, Scotiabank2: Yes, this is Graham. PDH 2 has been running much better and much consistently since the turnaround that we had last year. The teams have put a lot of work in, worked very closely with our licensing partner and have resolved a number of the issues that we had and are looking forward to sustained operation of that unit.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: How about PDH 1?

Brandon Bingham, Analyst, Scotiabank2: PDH 1, as well. You know, 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 1, 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. The teams, we’ve got good teams working out there, and they’re just knocking down the barriers that we’ve had out there over previous years and good work by those folks out at our Mont Belvieu PDH team.

AJ O’Donnell, Analyst, TPH&Co.1: Perfect. My quick follow-up is the macro comments you made at the beginning of the call, which were actually very informative. You know, you talked about 15 million barrels of total disruptions and then Strait probably normally operating maybe only in July. I’m just trying to understand what does this do to, you know, various storage levels of crude, refined products, LPG? 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.

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: If we look at the numbers, and I think Jim was pretty spot on with saying, around 500 million barrels a month of lost supply, depending on who you ask. As he pointed out, it’s somewhere between 10 million-15 million barrels a day of lost supply through the Strait of Hormuz. That’s crude oil products and NGLs. Just take 12 million barrels, for example, multiply that times 60 days, you’ve lost 720 million barrels through the Strait for global supply. Imagine if we can get back to normal, and let’s say we’re down a handful of barrels, you’re only gonna get maybe 1 million or 2 million barrels above that. It could take years to get back to where we were before the war.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: You know, 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.

AJ O’Donnell, Analyst, TPH&Co.1: Thank you so much.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of John Mackay of Goldman Sachs. Your line is open, John.

John Mackay, Analyst, Goldman Sachs: Hey, good morning, everyone. Thank you for the time. I just wanna go back to the 2027 kinda soft guide from the last call. You talked about it a little bit earlier in this one, but I just wanna 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 kinda softer 2026 macro environment or a 2025 macro environment where we weren’t gonna have a lot of spreads? Or was 2027 meant to be a more kinda normalized environment, maybe closer to what you outlaid, you know, outlined in the fundamentals update a couple weeks ago? Maybe just kinda walk us through the kind of macro behind the 27 piece.

Brandon Bingham, Analyst, Scotiabank0: John, this is Randy. I appreciate the question. Really what we were looking at when we saw the potential for 2027 was really just fee-based, fee-based EBITDA growth. You know, we were in a situation in 2025 and coming into 2026, Jim mentioned earlier that it was really a benign environment for commodity prices and spreads. Really, the driver was really fee-based cash flows off of 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 were really the drivers.

John Mackay, Analyst, Goldman Sachs: I appreciate that. That’s clear. Thank you. Then maybe just switching to kind of the broader macro, you have commented a couple of times on this call about the disconnect between the, let’s say, paper market and 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?

Brandon Bingham, Analyst, Scotiabank2: Yeah, this is Todd. I mean, you’re seeing strong physical premiums, for example, in Dated Brent. I really think what we’re alluding to is the forward market may not be accurately reflecting what we’re seeing in the physical market. It’s probably not high enough.

John Mackay, Analyst, Goldman Sachs: Makes it 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 clearer resolution in the Strait?

Brandon Bingham, Analyst, Scotiabank0: it sure looks like.

John Mackay, Analyst, Goldman Sachs: It looks like it. All right. I appreciate the time. Thank you.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Gabe Daoud of Truist. Your line is open, Gabe.

Gabe Daoud, Analyst, Truist: Thanks, operator. Morning, everyone. Thanks for the time. Was hoping maybe to just touch on the gas side just for a second. Maybe Haynesville gathering. Is there in the shoulder season now in front month at $2.50. We’ll see what happens in the summer. Curious if you’re seeing any change in behavior. It does seem like privates build productive capacity to turn on at the appropriate price signal, but curious if you’re seeing any change in behavior.

AJ O’Donnell, Analyst, TPH&Co.4: This is Natalie Gayden. You know, you’re right. The privates, you see some rigs, or quite a few rigs actually running. I think we expect a little bit of pop on our system in the Haynesville at the end of the year. 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.

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: All right, Natalie.

Gabe Daoud, Analyst, Truist: Got it. Thanks, Natalie. Just a quick follow-up, maybe shifting back to the Permian as the commercial team tends to win some new business, obviously competitive basin. Just curious, what’s most important to producers today? Is it, you know, reliability, just given where pricing is, fees, maybe, you know, differentiation given your tower gas capabilities? Just trying to frame the competitive dynamics today. Thanks, guys.

AJ O’Donnell, Analyst, TPH&Co.4: Well, we always use our integrated value chain to compete. There’s no doubt about that. 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 is a competitive advantage ’cause you’re already there. When producers wanna bring on gas and, you know, the next 12 months, you already have a foot in the door per se. I would say a mix of all of the things, integrated value chain and just geographical position in the basin.

AJ O’Donnell, Analyst, TPH&Co.9: This is Tyler.

Gabe Daoud, Analyst, Truist: Yes.

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

Yep, understood. That makes sense. Thanks, everyone.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Julien Dumoulin-Smith of Jefferies. Your line is open, Julien.

AJ O’Donnell, Analyst, TPH&Co.6: Hi. Good morning, everyone. This is Rob Mosca on for Julien. On the CapEx revision and the planned FIDs, would imagine you’d line aside to these projects when you issued guidance last quarter. Should we interpret this to mean that incremental FIDs like a new frack bias 26 CapEx higher? Is, you know, what you have now actually a pretty firm number? Also, you know, maybe if you could provide an update on those commercial agreements you spoke to with Exxon last quarter. Thanks.

Brandon Bingham, Analyst, Scotiabank0: The first part of your question, no, our CapEx guide does include anticipated projects that are under development. I won’t, I won’t 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 and our guide. We just did not know as far as when we were gonna come in and actually FID those. The FID, again, just with the volume growth we’ve seen in the Permian, the FID came earlier.

That was, if you would, the reason for the increase in the CapEx guide for this year, ’cause we’ll see some of that CapEx happening late this year.

Brandon Bingham, Analyst, Scotiabank1: This is Zachary S. Strait. On the NGL side, on the fractionation side, you know, Natalie mentioned she’s probably up on the upper end of her guidance. 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. We got a lot of levers. We’ll see if we need another fractionator, and if we do, we’ll build one.

AJ O’Donnell, Analyst, TPH&Co.9: Not sure what your question is on the Exxon side. On the downstream agreements, I would say a lot of those agreements were just extensions of deals that we already had, and it was just a natural fit while we’re in the conversations about Bahia to go ahead and extend those contracts.

AJ O’Donnell, Analyst, TPH&Co.6: Got it. No, that addressed it. Thanks for that. And for my follow-up, just wondering how we should think about the quantum of LPG that could be shipped out of NRT 2, once Phase 2, 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. And wondering how contracted that capacity is until the EHT expansion comes online, on the LPG side at the end of this year. Thanks.

AJ O’Donnell, Analyst, TPH&Co.9: Yeah, this is Tyler Cott. I’ll just reiterate again that over the longer term, you know, we’re contracting around the range of 90%. We have propane contracts that will start to ramp pretty quickly at NRT. 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.

AJ O’Donnell, Analyst, TPH&Co.6: All right. Appreciate the time, everyone.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of AJ O’Donnell of TPH&Co.. Please go ahead, AJ.

AJ O’Donnell, Analyst, TPH&Co.: Morning, all. 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 gonna 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. Just wondering, given that, you know, Phase 2 of Neches 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, you know, the return profile of your two new export projects.

Jay Bany, Senior Management, Enterprise Products Partners: Yeah, we’ve seen elevated spot rates. They’ve been volatile. You know, they’ve been as high as kinda 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. 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.

AJ O’Donnell, Analyst, TPH&Co.: Okay, great. I just had one more on the crude business. Looking at the Q1 results, could you provide a little bit more detail on kind of the specific drivers behind the lower sales margin and lower transport revenues? Curious, you know, with the higher commodity strip and overall volatile basis spreads that you guys have been citing, is this something that we could see kinda, you know, reverting in Q2 and the rest of the year? Thanks.

Jay Bany, Senior Management, Enterprise Products Partners: Yeah. AJ, this is Jay again. You know, Q1 results, you know, we had a headwind with the Eagle Ford JV renegotiation on some fees there, and then some mark-to-market noise, lower spreads. You brought up looking forward, the spreads increasing. That really didn’t take place until, call it, April business, but your point’s valid. We see it definitely at least as April looks now, that turning around.

AJ O’Donnell, Analyst, TPH&Co.: Okay. Thank you very much.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Jeremy Tonet of J.P. Morgan Securities. Your line is open, Jeremy.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Hi, good morning.

Jay Bany, Senior Management, Enterprise Products Partners: Good morning.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Just wanted to come back to some of the commentary that you provided on the macro level. Just wanted to see, I guess, you know, the industry, as you said, I don’t think has really responded with a lot of new rig activity. Wondering what you think the industry would need to see in the market to, you know, pick up activity, and do you expect us to get there?

Jay Bany, Senior Management, Enterprise Products Partners: I think we hear from producers is they’re gonna stay disciplined. Go ahead, Natalie.

AJ O’Donnell, Analyst, TPH&Co.4: I think that’s true. I mean, we’ll stay disciplined. We have a few companies that may break out from the pack, but they’re private in nature and, you know, don’t add a whole lot to the bottom line. That’s what we’re seeing.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Do you see any certain price levels out there in the, in the, you know, the 2027 curve that might, you know, start to warrant more activity or just can’t tell that?

Brandon Bingham, Analyst, Scotiabank2: Nope. This is Todd. I don’t think it’s necessarily a specific price level. It’s probably more focused on the back of the curve being lifted up, and not just next year. Needs to get lifted up for many years beyond that.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Got it. Thanks. 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, you know, projects that have not taken FID yet. Just trying to get a sense for how that might look.

Brandon Bingham, Analyst, Scotiabank0: Oh, for 2026? Jeremy, that’s getting pretty granular.

Jeremy Tonet, Analyst, J.P. Morgan Securities: For 27. 27 works as well. Thank you.

Brandon Bingham, Analyst, Scotiabank0: Probably for 2027, Chris, I mean, I would say probably half of 2027 is not spoken for.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Yeah. That’s very helpful.

Brandon Bingham, Analyst, Scotiabank0: Yeah.

Thank you.

Somewhere between 50% and 65%.

Jeremy Tonet, Analyst, J.P. Morgan Securities: Thank you.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Keith Stanley of Wolfe Research. Please go ahead, Keith.

AJ O’Donnell, Analyst, TPH&Co.0: Hi. Good morning. Wanted to clarify on Neches River Phase Two. 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? Just want to confirm the timeline. You would switch to ethane, you’re required to do that at year-end.

AJ O’Donnell, Analyst, TPH&Co.9: We do have propane contracts that we’ll be ramping up here at NRT on the flex train. As EHT comes online, we’ll satisfy that contract demand long term at EHT. Our ethane commitments are generally driven by when the VLECs arrive. Largely that’s later this year and into next year.

AJ O’Donnell, Analyst, TPH&Co.0: 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?

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Frankly, I think ethane has surprised me, the appetite for it. I can see that growing. Another one is we’re gonna ship out what, Chris? 3 million barrels of ethylene this month?

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: That’s right, Jim. Yeah, our ethylene exports over the last couple months have been really high.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: 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 dock, we’re a hydrocarbon dock. I think I’d like to see that grow. We’ve got our own target support where we’d like to be that I’m not gonna share, but I like the broadening of the offerings rather than a specific project.

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: Got it. Thank you.

Brandon Bingham, Analyst, Scotiabank0: Yeah, probably the only thing I’d add to that, just really what this, 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. That’s much improved.

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Yeah, healthy petrochemical business is good for Enterprise. They were running pretty strong before this. What’s changed? They’re making a heck of a lot of money.

AJ O’Donnell, Analyst, TPH&Co.0: Thank you.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. Our next question comes from the line of Jason Gabelman of TD Cowen. Please go ahead, Jason.

Jason Gabelman, Analyst, TD Cowen: Yeah. Hey. Most of my questions have been answered. I wanted to ask about another commodity exposure you guys have around octane enhancement. you know, I think in 2022, that business did in 2023, north of $400 million of gross margin. How are those spreads looking right now? Do you see that repeating this year?

Jim, Co-Chief Executive Officer, Enterprise Products Partners: Yeah, we just now are coming out of a turnaround on our Oleflex unit, and, so we’re not able to get full capacity, but we’re coming out of that, and we think it’s gonna be strong through the quarter.

Jason Gabelman, Analyst, TD Cowen: Got it. That was it for me. Thanks for the question.

AJ O’Donnell, Analyst, TPH&Co.5: Thank you. I would now like to turn the conference back to Joseph Theriac for closing remarks. Sir?

Joseph Theriac, Vice President of Finance and Investor Relations, Enterprise Products Partners: Thanks, Latif, and thank you to our participants for joining us today. That concludes our remarks. Have a good day.

AJ O’Donnell, Analyst, TPH&Co.5: This concludes today’s conference call. Thank you for participating. You may now disconnect.