Prepared remarks
Thank you for standing by, and welcome to Enterprise Products Partners LP's Second Quarter 2026 Earnings Conference Call. I would now like to hand the call over to Joe Theriac, VP of Finance and Investor Relations. Please go ahead.
Thanks, Latif. Good morning, and welcome to the Enterprise Products Partners conference call to discuss second quarter 2026 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise's General Partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn it over to Jim.
Thank you, Joe, and good morning, everyone. Enterprise reported strong volumes, earnings and cash flow for the second quarter. These results were driven by strong global demand for U.S. energy, which was particularly strong during April and May. Our export facilities, pipelines, storage assets and fractionation complexes altogether provide our customers with reliable access to both domestic and international markets. Our teams responded exceptionally well to the elevated demand levels. In the second quarter, we generated a record $2.8 billion of EBITDA, a 17% increase over the second quarter of last year, and that provided 1x coverage of our distributions. We handled record pipeline and marine terminal volumes during the quarter. Total pipeline volumes were up 8%, and our marine terminals were up an outstanding 33% compared to the second quarter of last year. We moved 14.7 million barrels a day of oil equivalent. I remember being ecstatic when that was 10 million barrels a day. Now we're knocking on the door of 15, and we moved 2.8 million barrels per day across our docks. I think it's important that we recognize our engineering and operations teams for their outstanding execution during the quarter. Their efforts enabled Enterprise to accelerate construction activities and begin commissioning the expansion of our Neches River NGL marine terminal ahead of schedule. The team demonstrated exceptional responsiveness and operational excellence while meeting strong customer demand and maintaining the high standards of safety and reliability that define Enterprise. Natural gas processing inlet volumes increased to 8.1 billion cubic feet a day. In the Permian, we saw a 14% increase over the second quarter of last year, bringing our total inlet volume in the basin to 4.3 billion cubic feet a day, reflecting continued gross growth in producer activity across both basins. To support this growth, we recently approved the construction of Plant 11, a new 300 million cubic feet per day natural gas processing plant in the Midland Basin, and Plant 13, a new 300 million cubic feet per day plant in the Delaware. Beyond providing additional processing capacity for our upstream customers, these plants will supply incremental wide-grade volumes into our basin NGL pipeline systems. Those systems are currently operating at 86% of capacity. Those volumes would then move through our NGL value chain supporting additional throughput across our fractionation, storage and export assets. We also approved the construction of NGL frac 15, a new 150,000 barrel per day fractionation facility located in Mont Belvieu. We expect Delaware Plant 13 will be placed into service in the third quarter of 2028, Plant 11 in the Midland Basin in the first quarter of 2029 and Fractionation 15 in the first quarter of 2028. These are exactly the type of projects creating value across our system and generating attractive long-term returns. One of the themes that continues to shape energy markets today is the growing importance of reliability and flexibility. Global energy markets remain highly dynamic and international demand patterns continue to be volatile. Rather than reacting to every market movement, we continue to focus on what we do best: optimizing our assets around changing conditions. Our network of assets provides connectivity from the wellhead to domestic and international end markets. We are well positioned to capture value across multiple points along our best value chains. That flexibility continues to be one of Enterprise's greatest competitive advantages. The next major project scheduled for completion is our LPG export terminal expansion on the Neches River channel. That should be in service by the end of this year. We're excited about the opportunities this will create as global demand for U.S. hydrocarbons continues to grow. Our outlook remains very constructive. Demand for U.S. energy, natural gas liquids, petrochemical feedstock and export services continues to support utilization across our system. Combined with a strong balance sheet, substantial retained cash flow and a disciplined capital program, we're well positioned for growth. And finally, I think it's important to thank our employees for an outstanding quarter. Their commitment to safety, operational excellence, customer service and execution continues to drive our success. With that, I'll turn it over to Randy.
Okay. Thank you, Jim. Good morning, everyone. Starting with cash flow. The partnership's adjusted cash flow from operations, which is our cash flow from operating activities before changes in working capital, increased 19% to a record $2.5 billion for the second quarter of 2026 compared to $2.1 billion for the same quarter last year. We increased our declared distribution to $0.56 per common unit for the second quarter of 2026, which is a 2.8% increase over the distribution declared for the same quarter in 2025. This distribution will be paid August 14 to common unitholders of record as of the close of business on July 31. The partnership repurchased $159 million of its common units during the second quarter of 2026 and $275 million for the first six months of the year. Total repurchases for the last 12 months were $404 million, bringing the cumulative utilization of our $5 billion buyback program to 34%. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 1 million common units on the open market, approximately $40 million, during the quarter. For the 12 months ending June 30, 2026 Enterprise paid out approximately $4.8 billion in distributions to limited partners. Combined with the $404 million of buybacks over the same period, Enterprise's total return was $5.2 billion resulting in a payout ratio of adjusted cash flow from operations of 56%. Total capital investments were $1.2 billion in the second quarter of 2026, which included $1 billion of growth capital projects and $140 million of sustaining capital expenditures. We currently believe our expected range of gross capital expenditures for 2026 will net to $2.9 billion to $3.4 billion after applying approximately $600 million in proceeds from asset sales we already received. The increase in 2026 capital investment since the beginning of the year primarily reflects the initial spending on long lead items for the 11th natural gas processing plant in the Midland Basin, the 13th natural gas processing plant in the Delaware Basin as well as NGL frac 15 in Mont Belvieu, and capital for natural gas gathering, compression and power generation facilities to support our growth in the Permian Basin. For 2027, we expect our growth capital expenditures to be in the $3 billion area. Sustaining capital expenditures for 2026 are expected to be approximately $600 million. On both the fourth quarter 2025 and first quarter 2026 earnings calls, we stated that discretionary cash flow for 2026 had the potential to be in the $1 billion area. Even though our estimate for growth capital expenditures for 2026 has increased by over $700 million as a result of investment sanctions since the beginning of the year, we still believe discretionary free cash flow for 2026 has the potential to approach the $1 billion area. Our total debt principal outstanding was approximately $33.5 billion at the end of the quarter. 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 97% of our debt was fixed rate. At the end of the quarter, our consolidated liquidity was approximately $4 billion, including availability under our credit facilities and unrestricted cash on hand. Recently, we closed on an incremental $1 billion short-term credit facility, which brings total liquidity to approximately $5 billion. We elected to add this incremental $1 billion of credit capacity due to the ongoing volatility in commodity prices and the potential impacts higher commodity prices may have on our need for working capital. At the end of the quarter, our consolidated leverage ratio decreased to our 3.0 target on a net basis after adjusting debt for the partial equity treatment of the hybrid debt and also reduced by our partnerships' on restricted cash on hand. Our leverage target remains at 3x plus or minus 0.25. Joe, before we turn it over to you, I guess we need to address the elephant in the room.
You're talking about my retirement? Yes. I've always said in Enterprise, retirement is 100 or death, whichever comes first. Well, I'm not 100, and I'm not dead. But at 81, 50 years in this business, 22 at Dow, 28 at Enterprise, it comes a time when you have to turn it over to the next generation. And we've got some unbelievable talent in this company. What I think I'm going to miss the most is big interaction with the people, even with Tug. And we just have some special people here. I've known Randy — I've worked with him for 28 years, the last couple of decades I think we've been a hell of a team, and I'm proud to have worked with him. It's been unbelievably rewarding to be with a company that when Randy and I were first here had an Enterprise value of $1.8 million and now is over $120 billion. It's been a hell of a ride. And the last thing I'll miss is all the poking Randy does with me throughout the day. And hopefully, Randy picks that up. Over to you, Joe.
Thank you, Jim. And Latif, with that, we're ready to open up the call for questions.
Questions and answers
Our first question is from Jean Ann Salisbury of Bank of America.
Congrats to you, Jim, on your retirement. I hope you get to doing some really nice whiskeys with your newfound time, and thank you for all the help over the years. So my question is probably for Corey: LPG listing rates have fallen as you brought on Neches River — did this surprise you? A lot is obviously going on in the market at the same time. But I guess my question is, is LPG export capacity already overbuilt? And as my follow-up in a related vein, would you expect to see the 300 kt expansion that you're coming on later in the year to be more fully utilized since it's more take-or-pay?
Jean, this is Tyler Cott. I will take that one. Yes, you're correct. There's a fair amount of export capacity that's come online and will be coming online, including our project and some other projects in the market over the next 12 to 18 months. And obviously, it will take the market a little bit of time to absorb that capacity. So we may see a period of time where we have less volatility in terminal fees and just overall lower rates than we've seen in the last couple of years. From our standpoint, we've been very intentional about contracting our capacity. So our EHT expansion and really all of our system-wide capacity around LPG export — as we've said, we're about 90% contracted. So we have relatively limited exposure to that scenario. So we feel good about where we're at given how things look for the next couple of years.
And Jean, this is Terry. I'll just add that Neches River Terminal has additional ethane volumes coming online and as we utilize that capacity, we're going to ramp up ethane transitions supporting propane PDH opportunities.
Our next question comes from Spiro Dounis of Citi.
Jim, congrats as well on the upcoming retirement. First question, maybe just starting with the fundamental one. If we go back to your fundamental update earlier this year, you suggested a meaningful amount of natural gas and NGLs were being curtailed beyond the system just due to Waha prices. Obviously, those pipelines are coming online now. So curious to have a sense for how much of that curtailed volume has come back to the market? What's still left to come? And maybe what that means for your 2027 outlook?
This is Corey. When we had our forecast, I would say that our forecast really hasn't changed all that much. Looking at producer cadence, not a lot has changed for the large public companies and the private operators. Some of the private producers that have come online are a bit more measured given some of the price volatility that we've seen and to add rigs on natural gas because the pipelines have come up a little bit faster than I think the market expected. So we've had some pretty strong Waha prices. As time goes on, I think we're going to end up filling those bases with gas that comes online as we expected would show up, and also some of these gas benches over time will start to fill pipeline capacity.
Great. Second one, maybe just going to CapEx, specifically around 2027. Curious how much of that $3 billion is sanctioned versus potential, and to the extent there's still more or less to fill there. Should we assume it's largely natural downstream extensions, more exports, or could it be something else? And more broadly, should we think about that $3 billion as a new baseline for growth CapEx? Or are you still anchoring that $2 billion to $2.5 billion longer term?
Spiro, I think in the near term, the $3 billion might be the new level, and some of it is just the pace of growth that we continue to see in the Permian and what we need there. In terms of natural gas gathering, compression and power generation — it seems like especially in the Delaware, whatever you're going to build, you've got to burn your own power, so I think that increases levels as well. As far as when we look out into 2027, probably 80% plus is already spoken for, just with the projects that we've sanctioned and have announced.
Our next question comes from John Mackay of Goldman Sachs.
Congrats from us as well, Jim. I want to go back to Spiro's first comment on the Waha picture. More specifically, you've been talking about kind of 2 Bcf a day of potential production when these places come back. Can you frame up for us just from an operator perspective, what that actually looks like? Are these existing wells being choked back? Are these maybe wells that have been completed but not actually turned in line yet? And maybe more specifically what these producers might be looking for from a Waha price or something else perspective to really bring those volumes on?
John, it's Natalie Gayden. When we were estimating the amount of gas shut in, it was a combination of producers we knew were shut in. It's typically the higher GOR producers that are exposed to Waha. So as that gas comes back online — and you asked the question, have wells not been produced at all — a lot of it has just been choked back. But I would say as that volume comes back online, we see that as more positive long term than short-term volatility. Not all producers need a particular positive Waha price to bring out 2 Bcf a day online. They need a healthy gas price, a healthy Waha gas price, that supports their economics. We've seen improvements in processing margins and that's true. We benefit from spread value and our equity gas production as well.
We benefit with our equity gas production we have. So all good.
Yes, absolutely. That makes a lot of sense. And maybe just taking some of those latter comments, certainly, the second quarter benefited from some of these spreads. Just curious, your outlook for the back half of the year or into 2027, your ability to kind of keep holding some of those, whether it's been through hedging it out or maybe the kind of market environment staying constructive? Maybe just walk us through the next couple of quarters on a couple of those fronts.
I'll speak to what we saw in the second quarter. During the months of April and May, we saw an acute global demand for U.S. energy. There was a significant demand pull across crude, LPG, ethane and olefins and product docks. We saw that in the form of additional volume and higher margins. For the quarter, it resulted in around $200 million associated with that global need for energy. So you break that $200 million down, call it 1/3 NGLs, 1/3 crude and then 1/3 petrochemicals and others. As of today, those strong cash differentials have largely normalized.
And in the next couple of quarters, when does the next capacity come online?
Yes. And look, we've spoken to it in the past, time and time again, but if volatility is there, the team will execute on it and deliver time and time again.
Our next question comes from Julien Dumoulin-Smith of Jefferies.
This is Andrew on for Julien. And Jim, congrats on your retirement. Just two quick questions from my front. The first one being, we're seeing a sequentially stronger quarter in crude, both from a volumetric and a per-barrel margin standpoint. Can you unpack a bit more in terms of how much of that is driven by equity barrels benefiting from the current crude volatility versus how much of that is long-term contracts? And maybe an extension of that: how much extra barrels moving from Midland to Gulf Coast — how is the recontracting conversation been on spare capacity on Midland to Houston?
If you look at the crude numbers at a high level, we benefited from higher Midland-to-Houston pipeline spreads, and we also benefited from the higher margins we're able to charge at the dock due to strong cash premiums. On the contracting side, Jay and his team have done an amazing job continuing to remain highly contracted on our Midland ecosystem and continuing to get additional contracts.
Yes. That's very clear. My second question: we've talked about a better outlook at the Permian from a gas perspective. Has that changed your expectation around potentially recontracting the volumes on ATEX around volumetrics as well as from a margin standpoint? Can you help frame your latest perspective on the magnitude of exposure here?
Andrew, this is Justin Kleiderer. On ATEX, it's still a dynamic conversation with our shipper customers — really just evaluating on a high level what's the highest and best use of the pipe. But that's also a function of the fact that current tariffs often exceed the value of the product that it moves. So there's going to be some degree of a rate reset, and we're just working with our customers to figure out what's the best and highest use of the pipeline and what gives them the assurance that they desire. We're engaging in those discussions; more to come as that unfolds.
Our next question comes from Keith Stanley of Wolfe Research.
Randy, wanted to start by clarifying your free cash flow commentary for the year. So you raised the CapEx by $600 million to $800 million, you said you still expect free cash flow to approach $1 billion. So is that simply due to much higher EBITDA than you previously expected? Or are there any other items like working capital or other items that are driving that?
Keith, we really don't include working capital in that when we think about discretionary free cash flow because working capital will ebb and flow around commodity prices and other dynamics. It really comes down to two moving pieces: EBITDA and growth CapEx. While we've seen over $700 million increase in growth CapEx because of excellent project opportunities, at the same time, our cash flow is up significantly, which basically almost offsets the increase in growth spending.
Great. Second question: you're building now five Permian plants at one time. I think your historical cadence was more like due one at a time. Would you characterize the driver of that as a faster growth outlook for the basin? Are you having more commercial success and winning market share? And what do you expect as a planned kind of run-rate cadence from here?
I would expect trending closer to two plants per year is probably the right answer. Of course, as producers change their cadence or drill zones with higher GORs, that obviously changes our assumptions. Five plants in the next roughly three years, because one starts up in 4Q 2026, puts us at around 1.7 per year cadence. And then we haven't even discussed potential projects beyond 2028 yet.
Okay. So more of a heightened period right now and then back to about two per year after that?
Yes. One thing to note: since 2022, we've probably been increasing our capacity by a compound annual growth rate of roughly 15%. From the end of 2025 to the end of 2028, we're going to grow it by about 11%. In the second quarter this year versus second quarter last year, our Permian inlet volumes were up 14%. Each one of the plants tracks roughly 45,000 barrels a day of liquids that flows into Mont Belvieu and right into our fractionation complex and then into our downstream assets. So really good positive development.
Our next question comes from Theresa Chen of Barclays.
I want to go back to the export topic. Looking past the recent volatility on export arbitrages, but focusing more on the long-term strategic reliance on U.S. energy exports in general: are you seeing much change in customer behavior or contracting activity or interest from customers that have not come across your commercial footprint before? Any color around that would be helpful.
Theresa, yes. We said last time we had strong interest before the conflict, and we still have very strong interest. There has been a bit of increased interest from countries that historically were more dependent on Middle Eastern supplies looking to shift some of their long-term sourcing to the U.S. That's a function of that exposure and just the fact that U.S. exports are growing, and we're clearing to some new markets as well.
Got it. And with multiple refined products infrastructure assets under development, maybe closer to FID and not across your competitors, how does this change your view of product flows on both refined products within your footprint, but also heavier molecules within the NGL footprint between Gulf Coast, Mid-Con and regional bodies?
Theresa, on the product side: our TE (transportation/exchange) system moves products from the Gulf Coast to the Mid-Con in Chicago. As the Gulf Coast basis has weakened at times, volumes on that system have been pushed further south. Anything that debottlenecks or clears overhang in the Mid-Con and Chicago area with projects currently under development should benefit our system. Directionally, we want to see prices that support more product movements from the Gulf Coast further into markets.
Our next question comes from Gabe Daoud of Truist.
Jim, congrats to you as well. I was hoping you could give an update on the sour gas side of things. It looks like you're drilling your third AGI train currently, which should bring treating capacity to 750 million cubic feet a day. Are you seeing any incremental growth opportunities beyond that on the sour gas side?
Demand has remained strong. The system was essentially full prior to the new trains coming into service. We have five under construction; as you know, the third AGI train is underway, and we're currently evaluating Train 6 mainly because producer activity and interest continue to build. Given that, I would expect volumes and margins to continue to grow.
Got it. And then as a follow-up, last quarter you had quantified the EBITDA uplift in 2026 from outperformance. Given the strength year-to-date, could we get an update on thoughts around the EBITDA outperformance this year and how we should think about the trajectory into 2027?
We talked about this on the first quarter call and I used the word modest. We were expecting modest EBITDA growth from 2025 into 2026, largely based on an oversupplied energy market with benign pricing. The conflict in the Middle East created volatility and drove demand for U.S. energy. Any comment about 2026 and 2027 depends on how that conflict evolves, so it's hard to predict. At the beginning of the year we said modest EBITDA growth in 2026 with the potential for around 10% growth into 2027, and that potential was largely due to volumes coming on through the system — whether volumes into new assets or those related to acquisitions such as Oxy Rock, which will pick up volumes at the beginning of 2027. That 10% potential was volume-driven and not reliant on commodity price moves. Any incremental demand across the docks or optimization opportunities is on top of that. So that's where our thoughts remain, recognizing the uncertainty.
Our next question comes from Jeremy Tonet of JPMorgan.
Jim, wishing you the best in retirement. We have appreciated your perspective over the years.
Thank you, Jeremy.
Just wanted to turn back to the Permian and Waha pricing: it's turned positive and seems to be staying positive for a bit. There's a lot of gas that is ready to be connected. How long do you see Waha remaining in positive territory? And looking further out, after the current round of pipeline additions, when might new constraints re-emerge — would the industry need another pipe in 2029 or 2030, or how do you think about that?
I won't try to predict Waha prices. We could see Waha tighten again before 2027 as some shut-in gas returns and some backloaded production comes online. But we'd rather see a healthy Waha that supports our producers' economics and volume growth. Sustained volumes growing across our integrated system are more valuable than short-term basis dislocations.
There's obviously a lot of gas in the Permian and pricing will reflect how infrastructure comes to market and the timing. I expect some continued volatility.
Regarding future expansion, it depends on your view of the wet gas forecast. We believe higher GORs are likely, so it really depends on where producers choose to drill and the timing of any yet-to-be-announced pipeline projects.
And just curious about PDH operations — it seems like they ran better this quarter. How did they look in Q2 and so far in Q3?
This is Graham. Second quarter was a good run for us on the PDHs. PDH 2 ran at design conditions throughout the quarter and had a good run. PDH 1 had one minor issue in the second quarter. As for the third quarter, we did have an issue in July where PDH 2 was down; it is back up and running. PDH 1 is running stable as expected for the quarter.
Our next question comes from the line of an unidentified caller.
Congrats on your retirement, Jim. Most of my questions have been asked already, but I do have one directed at Natalie. Looking at natural gas processing volumes of 8.1 Bcf this quarter, they were up slightly year-over-year even as the Permian inlet grew 14%. Relative to Q1, they were down a little bit. Can you provide additional context on what's going on with processing volumes outside of the Permian and how you expect those to look over the rest of the year?
If your question is about volumes outside of the Permian, those have been relatively muted. Growth in Permian capacity is still slightly tight, but there is a significant amount of processing capacity coming online in the basin — not just with our projects, but with some competitors as well. As mentioned, quite a bit of gas was shut in due to Waha prices. As some of that returns, you'll see volumes come back online across our plants and others'. Overall, it's a stable basin with ebbs and flows, but nothing unusual beyond what we've discussed.
Our next question comes from Manav Gupta of UBS.
You are somewhat unique because you're one of the biggest exporters of ethane. Can you talk a little bit about what you're seeing in terms of VLGC availability, that ramp, and how that increases your ability to export even more ethane to global markets given the demand? Also, given demand growth from both the power side and LNG, some say the Haynesville could become more of a core basin besides the Permian and Marcellus. Can you talk about your exposure to the Haynesville, what you see in terms of growth and how it could benefit the company?
Manav, yes. There's a pretty big uptick in VLGCs coming to the market — a few more this year and quite a bit more next year — and you should see our volumes correlate strongly to those VLGCs coming online as our customers get their vessels and begin lifting on contracts. There's certainly more demand beyond our current capacity, and we're in conversations with many parties around the world about additional demand for U.S. supply.
Perfect. Given demand growth from power and LNG, we're starting to see people call Haynesville a more core basin. Can you talk about your leverage to the Haynesville basin and what you see in terms of growth?
If you're asking what we see for Haynesville: it is a dry gas basin and very price-dependent. We'll see peaks when the basin steps into the market, but Permian continues to grow and we expect Haynesville to be a meaningful basin when pricing supports activity.
One thing to add: our Louisiana interconnect system for Haynesville extension has seen large demand; that pipe is sold out. The lateral that goes down to serve the LNG markets is running between 800 million and 1 billion cubic feet a day and is sold out. We're seeing good demand pull across that intrastate system, but as Natalie said, Haynesville is cost dependent.
Manav, one more point: we've seen production growth in the Haynesville slowly creep its way up over the year. We're getting pretty close to 16 Bcf per day in total U.S. production from Haynesville. If that trend continues, it's constructive for the market and for our systems.
Thank you. I would now like to turn the conference back to Joe Theriac for closing remarks.
Thanks, Latif, and thank you to our participants for joining us today. That concludes our remarks. Have a good day.
This concludes today's conference call. Thank you for participating. You may now disconnect.