Enterprise (EPD) Q1 2026 Earnings Transcript

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DATE

Tuesday, April 28, 2026 at 10 a.m. ET

CALL PARTICIPANTS

• Co-Chief Executive Officer — Jim Teague
• Co-Chief Executive Officer & Chief Financial Officer — W. Randall Fowler
• Senior Vice President, Commercial — Tyler Cott
• Senior Vice President, Commercial — Jay Bainey
• Senior Vice President, Commercial — Natalie Gayden
• Senior Vice President, Petrochemicals — Graham Bacon
• Executive Vice President, Commercial — Tug Hanley
• Vice President, NGL Fundamentals and Analytics — Zach Stray
• Vice President, Petrochemicals — Chris D’Anna
• Director of Investor Relations — Joe Theriak

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TAKEAWAYS

• EBITDA -- $2.7 billion, representing a 10% increase, highlighted as "up 10%" and classified as the result of "an exceptional quarter."
• Net Income Attributable to Common Unitholders -- $1.5 billion, or $0.68 per common unit fully diluted, marking a 6% increase.
• Adjusted Cash Flow from Operations -- $2.3 billion, a 10% increase compared to $2.1 billion previously reported.
• Distribution Per Common Unit -- $0.55, up 2.8%, with 28 consecutive years of distribution growth forecasted by management.
• Coverage Ratio -- 1.8 times distributable cash flow, directly highlighted as a measure of capital strength.
• Capital Return -- $5.1 billion returned to equity investors over 12 months; $4.8 billion as distributions, and about $356 million as buybacks (subtotal does not equal total due to unspecified additional items).
• Capital Investments -- $988 million YTD; $783 million growth capital; $205 million sustaining capital; guidance for full-year growth capital spend after asset sale proceeds is $2.3 billion to $2.6 billion.
• Debt -- $34.2 billion principal; weighted average cost 4.7%; 95% fixed rate; weighted average life about 17 years; consolidated liquidity $3.3 billion.
• Leverage -- Net leverage ratio 3.2x, with stated target range of 2.75x to 3.25x.
• Buybacks -- 3.1 million units repurchased for $116 million in Q1; additional 1 million units acquired via other plans for $37 million.
• Operating Records -- Set 12 new records, including 8.3 bcf/d of natural gas processed (up 7%), 1.9 million bpd NGLs fractionated (up 16%), 2.3 million bpd loaded at docks (up 15%), and 14.2 million boe/d transported (up 7%).
• NGL Export Docks Utilization -- 90% contracted; LPG contracts extend through decade, ethane 10–20 years; 10% short-term spot availability.
• Neches River Terminal (NRT) Phase 2 -- Commissioning began in April, expected completion for both ethane and propane in May.
• Export Volumes -- 70 million barrels per month averaged across docks in the quarter, with April scheduled above 88 million barrels.
• Payout Ratio -- 57% of adjusted cash flow over trailing twelve months.
• Sustaining Capital Guidance -- $500 million to $580 million projected for the year.
• Future Growth Capital Expenditures -- 2027 guidance of $2.0 billion to $2.5 billion.
• Permian Natural Gas Processing Plants -- Two new plants FID'd; expected online in 2027 and described as additive to 2027 growth outlook.
• 2026 Discretionary Free Cash Flow -- "in the 1 billion area," with upside possible depending on commodity pricing and spreads.
• Buyback vs Debt Retirement Allocation -- Anticipated 50%-60% of discretionary free cash flow to buybacks for 2026.
• PDH Facilities Performance -- PDH 2 "running much better and much more consistent since the turnaround," with management noting continued investments in reliability for both PDH units.
• Midstream Acquisition Impact -- Increased net debt includes recent Occidential Petroleum asset acquisition, with related EBITDA growth expected to flow into trailing numbers going forward.
• Spread Gains and Volatility -- Management highlighted return of "outsized spreads," notable after a "benign" prior year, with first quarter benefits in "natural gas" and larger spread gains expected in Q2 post-conflict.
• International and Domestic Demand -- "International demand for US feedstocks is as strong as we have seen in quite some time," with distinctive pull-through on exports and petrochemical margins.
• Macro Tailwinds -- Middle East conflict and Strait of Hormuz closure have removed "12 to 15 million barrels a day" from supply chains, materially impacting volumes, spot rates, and customer contracts.
• Bottleneck/Capacity Expansion Commentary -- Fractionator 14 was full on day one; significant utilization across system assets; capacity addition cadence in Permian seen trending toward "I think we're probably trending closer to two. And, obviously, that depends on how GORs shape up, but Corey's showing you that GORs are increasing. That is true. So I'd say we're trending more to two per year."
• Commercial Contract Profile -- Crude contracts typically run through 2028–2029; NGL and LPG assets are generally 90% contracted long term, offering 10% available for spot opportunities.
• Asset Monetization -- $596 million received from ExxonMobil in Q1 for 40% Bahia NGL pipeline interest; related downstream contract extensions noted.
• Haynesville System Volume -- Stable, with expectation of a "pop" at year-end as private operators increase rig activity.
• SPR Barrel Release -- Management explicitly noted benefit from Strategic Petroleum Reserve volumes released to international markets, contributing to higher Q1 and expected Q2 export volumes.
• Octane Enhancement Segment -- Recent Oleflex unit turnaround constrained output, but management expects stronger operations for the current quarter.

SUMMARY

Management communicated a significant upward revision to internal expectations for 2026 due to ongoing commodity price volatility, geopolitical disruptions, and strong global demand for U.S. hydrocarbons, particularly in exports and petrochemicals. Guidance for 2026 discretionary free cash flow has the potential to be in the $1 billion area despite a $300 million increase in growth capital expenditures, supported by elevated earnings and surging export volumes. Large-scale assets recently placed into service—such as the Bahia NGL pipeline, Frac 14, and new Permian gas plants—are fully ramped or nearing full utilization, directly contributing to new system records and fee-based cash flow visibility. Management confirmed that contract structures across NGL exports and crude terminals remain durable, with most capacity secured under long-term agreements, and spot market exposure poised to benefit from recent dislocations. Executive commentary signaled continued discipline in capital allocation—maintaining stated buyback and debt reduction ratios—even as volumes, spreads, and customer activity surpassed expectations due to external supply shocks.

• Randy Fowler directly stated, "we think distributions to partners will grow commensurate with operational distributable cash flow per unit growth," reinforcing a predictable returns framework.
• Export dock contract durations extend through the decade or beyond, with only about 10% of capacity near-term available for spot utilization subject to market opportunity.
• Supply disruptions from the Middle East have substantially raised global margins for ethane-to-ethylene and ethylene-to-polyethylene, supporting record utilization by domestic petrochemical customers.
• Phase 2 of Neches River Terminal is expected to drive added flexibility and spot revenue once commissioning completes in May, with propane contracts ramping up and future transitions to ethane tied to vessel arrivals.
• Despite increasing capital investments, management emphasized that new long-lead projects and fractionation expansions are included in capital guidance, with the fractionator build pace able to adjust quickly to volumetric demand.
• Executives noted that, due to the large volumes removed from the market, hydrocarbon inventory replenishment worldwide "could take years to get back to where we were before the war."
• The buyback program remains flexible, with cash retained for opportunistic repurchases during equity price dislocations, as well as for routine programmatic execution.
• Executives highlighted improved reliability and sustained performance at both PDH and Oleflex units, following targeted turnarounds and investment.
• The company’s current $3.3 billion in liquidity and leverage at 3.2x support ongoing capital deployment and response to further market shifts.
• Management anticipates that "outsized spreads" will persist into the second quarter, with export, NGL, and natural gas businesses positioned to capture incremental revenue opportunities as global volatility persists.

INDUSTRY GLOSSARY

• PDH: Propane Dehydrogenation—facilities that convert propane into propylene, a key petrochemical feedstock.
• Fractionator: A plant or unit that separates mixed NGL streams into component products (e.g., ethane, propane, butane).
• NGL: Natural Gas Liquids—hydrocarbon products such as ethane, propane, butane, isobutane, and natural gasoline.
• EHT: Enterprise Hydrocarbon Terminal—a named export terminal for NGLs and other products.
• VLEC: Very Large Ethane Carrier—a tanker ship designed for ethane exports.
• FID: Final Investment Decision—a company's formal commitment to execute a capital project.
• SPR: Strategic Petroleum Reserve—the U.S. government’s emergency crude oil stockpile.
• GOR: Gas-to-Oil Ratio—the volume of gas produced relative to oil, used to track well productivity shifts.
• ARPs: Average Realized Prices—the net price received after all adjustments, frequently referenced for LPG exports.
• Occidential Petroleum acquisition (context): Recent acquisition of midstream assets from Occidental Petroleum, which has increased debt and is expected to raise EBITDA as the acquired volumes scale in the system.

Full Conference Call Transcript

Jim Teague: Thank you, Jim. We got off to a very strong start this year and the business is performing well across the board. In the first quarter, we generated 2.7 billion of EBITDA in a short quarter. 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, and if you look at Bahia and Shin Oak as a system, they're running at 80% of a combined 1.2 million barrels a day of capacity. Operationally, the quarter was outstanding. We set multiple operating records across the system. With the addition of Midtown West 2 in the Delaware Basin during the first quarter, we set a new record for gas processing plant 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, and we tend to embrace volatility. In January, winter storm firm gave us a strong start to the year. Elevated demand for natural gas and propane created price dislocations across our SFE 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 marketing teams and asset flexibility allowed us to capture incremental value, and this was only the beginning of the volatility we experienced during the quarter. The ongoing conflict in the Middle East and restricted flows through the Strait have driven a substantial increase in demand for all forms of US energy, petrochemicals, and refined products. The supply shock dramatically improved US 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 7¢ a pound. Today, they're 23¢.

The ethylene-to-polyethylene spread was 20¢ per pound; now it’s over 45¢. It's no wonder why my former employer’s stock is up over 50% year to date. International demand for US feedstocks is as strong as we have seen in quite some time. The loss of Middle East hydrocarbon supply fractured the Asian supply chain. China's PDHs are, we hear, currently operating at less than 50% of capacity. As a result, Asian petrochemicals have been destocking inventories by consuming derivative inventories. The impact to hydrocarbon markets around the world has been significant, and we see this strong demand continuing through the remainder of '26 and maybe into '27. The demand pull is showing up very clearly in our marine export business.

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

The combination of strong supply, growing export demand, and new projects ramping into service is creating real operating leverage across the business. We also saw strong contributions from the downstream side. In addition to record product flows, strong margins across our assets, and high utilization at our PDH facilities supported solid earnings and cash flow for the quarter. Our new assets are ramping well and 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. This 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. And that does not account for the time required to repair onshore production and refining facilities damaged in the war.

Until global supplies and inventories return to normal, we believe there will continue to be strong international demand for US energy and products. We're also seeing international consumers look to increase purchases of US energy as an avenue to improve the US 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.

Randy Fowler: Thank you, Jim, and good morning, everyone. Starting with the income statement items, net income attributable to common unitholders for 2026 was 1.5 billion, or $0.68 per common unit on a fully diluted basis, which is a 6% increase compared to 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 2026 compared to 2.1 billion for 2025. We declared a distribution of $0.55 per common unit for 2026. This is a 2.8% increase over the distribution declared for 2025. The distribution will be paid May 14 to common unitholders of record as of close of business on April 30.

We are on track for twenty-eighth consecutive years of distribution growth in 2026. To our knowledge, this is the longest period of distribution growth of any US midstream company and is an example of Enterprise’s consistency and commitment to returning capital directly to our unitholders. 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 twelve months ended 03/31/2026, 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% were 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 2026, which included 783 million of growth capital projects and $2.00 5 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 to 2.6 billion after applying approximately 600 million in proceeds from asset sales already received. For 2027, we expect our growth capital expenditures to be in the area of 2 billion to 2.5 billion. Sustaining capital expenditures for 2026 are expected to be approximately 500 to 80 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 growing 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% to 60% in buybacks. As we have said before, Enterprise's buyback program has both programmatic and opportunistic elements. In periods of momentum and volatility characterized by higher equity prices, we may elect not to chase price and instead retain cash in the opportunistic bucket for buybacks in future periods when momentum has [inaudible].

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 03/31/2026. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately seventeen years. Our weighted average cost of debt was 4.7%, and approximately 95% of our debt was fixed. At March 31, our consolidated liquidity was approximately 3.3 billion, including availability under our credit facilities and unrestricted cash on hand.

As Jim mentioned, adjusted EBITDA increased 10% to 2.7 billion for 2026. As of 03/31/2026, 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, Port Neches 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 for these investments is yet to flow into our twelve-month trailing EBITDA number.

Our overall leverage target remains at three times plus or minus 0.25 times, or 2.75 to 3.25. With that, Joe, I think we can open it up for questions.

Joe Theriak: Randy. Latif, we are ready to open the call for questions.

Operator: Thank you. As a reminder, to ask a question, you will need to press 11 on your telephone. To remove yourself from the queue, you may press 11 again. Please limit yourself to one question and one follow-up or two questions to allow everyone the opportunity to participate. Please stand by while we compile the Q&A roster. Our first question comes from the line of Theresa Chen of Barclays. Your line is open, Theresa.

Analyst: Good morning. Following up on the comments about the uptick for US energy demand in general and US 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? And longer term, how much incremental brownfield expansion capability do you have across your export assets?

Tyler Cott: Hi, Theresa. This is Tyler Cott. I'll speak to the NGL exports specifically. I think we've said before, our NGL export docks are contracted around the range of 90%. On LPG, those contracts go through the end of this decade. On ethane, they extend, you know, ten to twenty 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.

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

Tyler Cott: Sure. This is Tyler Cott again. Our operations team has done a fantastic job expediting a bit in the commissioning of Neches River Terminal. We're still in the process of commissioning it. Began in April, and at this point, we expect to complete commissioning for both ethane and propane sometime in May. In terms of spot utilization and earnings uplift, we really gotta get through the commissioning process here and see what we have. I think an important point to note about our business going forward is we have a significant amount of flexibility. So our spot business will be dictated across different products in terms of what the market needs at a given time. Jay?

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

Analyst: Thank you.

Operator: Thank you. Our next question comes from the line of Spiro Dounis of Citi. Your line is open, Spiro.

Analyst: 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. And then Randy, you seem to indicate that your operating cash flow is going to at least sort of mirror the increase in CapEx to keep that DCF/free cash flow kind of stable. So curious if you could give us an update on the sort of 3% growth you guys were talking about for '26 and the 10% growth you were talking about for 2027 on the last call?

And as you answer that question, just curious if these two new processing plants are additive to that '27 outlook.

Jim Teague: This is Jim. Yeah. I think I said modest in '26 and 10% in '27. I think we'll beat modest. Go ahead.

Randy Fowler: I mean, as you think about twenties—sorry. Go ahead. Yeah. Yes. Spiro, I sort of like the point you made in your note that probably modest is a low bar now, and I think you're right. You know, again, it's sort of hard to come in and look at 2026 because, again, that’s just what's the duration of these commodity prices gonna be and the duration of spreads. So really shaping up to be a much stronger year than what we expected. And, again, because we were really coming in and not expecting much benefit at all from commodity or spread and really were relying on our fee-based businesses.

So really hard to come in and give much guidance because 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 could be. So the endpoint is 2026 looks to be a much more favorable year than when we first started. Our commercial guys did a great job in underwriting two more natural gas processing plants in the Permian, which really will come on during 2027. We really did not have those baked into our 2027 numbers at the time, so that would be additive.

And then, from the same token, 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 Teague: 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.

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

Jim Teague: I don't know if it’s gonna be 500 million, 600 million, or 700 million, frankly. But 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.

Tug: Yeah. I'll just add, I mean, this first quarter, we had some outsized spreads on natural gas when a storm firm presented some opportunities. But largely, the spreads that we've seen post Iranian conflict, those will come second quarter.

Analyst: Great. Helpful color, guys. I'll leave it there. Thank you.

Jim Teague: Thank you.

Operator: Our next question comes from the line of Jean Ann Salisbury of BofA. Your line is open, Jean.

Analyst: 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?

Tug: Hi, Jamie. Yeah. This is Tug. So, yes, they were happy prior to the conflict, and they're even happier now. I will say that interest and demand we've seen on ethane—and I'll even throw LPG in there—we have quite the appetite for demand prior to the conflict, and I would say we have a similar appetite for demand post conflict. It made sense before, and it still makes sense today.

Analyst: That's helpful. And 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? What should we expect, like, basically a couple of years for them and you to build that capacity?

Jim Teague: That's probably—it’s not overnight, Jeanne. Yeah. And I think your couple of years is probably in the ballpark.

Analyst: Alright. Thank you. I'll leave it there.

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

Analyst: Thanks. Good morning, everyone. You know, at dinner a few weeks ago, 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 move more to the US, but you seemed to think that wouldn't happen. Curious just if you've had any change in your thinking there and, in a similar vein, I think at the time you didn't really think we'd see any reaction from US producers, and I'm curious if you still think that's the case.

Jim Teague: Take the second one first. Jay and Natalie, what reaction by US producers?

Natalie Gayden: This is Natalie Gayden. I'd say—and Jay can chime in here—I don't know that US producers have done much different. It seems to me that they're staying pretty disciplined. Sure, we see some movement in rig activity to different maybe producing zones or maybe different areas of their—if they have discretionary acreage. But other than that, I'd say they're keeping discipline.

Jay Bainey: 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 Teague: As to the first question, Jean Ann, you know, a supply disruption like we have changes a lot of things. And we're seeing interest from countries, Tug, like India. But, you know, it's a funny thing. We're geographically challenged when it comes to LPG and India. And the question will be, when this is all over and everything returns to normal, do they still wanna lift US LPG when the AG is supposed to [inaudible]. Right now, they're showing a lot of interest.

Analyst: Okay. Thanks for that. The second question was 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% or 60% allocation to buybacks versus debt paydown, or if that billion dollars turned into 1.5 billion, for example, would the incremental above plan just go to buybacks since your leverage is already within the target? Thanks.

Randy Fowler: Yeah, Michael. I like the way you're thinking this morning. Yeah. Michael, I think we would still, in the near term, when we think about 2026, we'd probably still have that 50% to 60% split. You know, 2027 could be a different story, but I think 2026 still probably maintains that split.

Analyst: Thank you.

Natalie Gayden: Thank you.

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

Analyst: Hey. Good morning. Thanks for taking the questions. I was just thinking about the two new plant announcements in the Permian. And I know it hasn't even really been a month since the update, but 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?

Natalie Gayden: This is Natalie Gayden. I think we're probably trending closer to two. And, obviously, that depends on how GORs shape up, but Corey's showing you that GORs are increasing. That is true. So I'd say we're trending more to two per year.

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

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

Analyst: Okay. Great. Thanks.

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

Analyst: 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. And I think you did do some kind of turnaround on the PDH unit too, and it's been operating better after that. Can you speak to those dynamics, please?

Graham: Yes. This is Graham. PDH 2 has been running much better and much more consistent since the turnaround that we had last year. The teams have put a lot of work and worked very closely with our partner, and have resolved a number of the issues that we had, and I'm looking forward to sustained operation of that unit. PDH 1 as well. And we've invested a lot over the years in improving the reliability, and we still have projects that we're working. But I think what you're seeing in PDH 1 is much improved reliability of that unit as well due to the investments that we've made over the last few years in reliability as well.

We've got good teams working out there, and we're just knocking down the barriers that we've had over previous years, and good work by those folks out at our Mont Belvieu PDH team.

Analyst: 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 the various storage levels of crude, refined products, LPG. Do you think, like, because of this depletion, storage levels could probably take a year or so to get fully replenished here? If you could talk about some of those dynamics, please.

Tug: So 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 and 15 million barrels a day of lost supply through the Strait of Hormuz. That's crude oil, products, and NGLs. So just take 12 million barrels, for example, multiply that times sixty days. You've lost 720 million barrels through the Strait for global supply. So 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.

So it could take years to get back to where we were before the war.

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

Analyst: Thank you so much.

Jim Teague: Thank you.

Operator: Our next question comes from the line of John Mackay of Goldman Sachs. Your line is open, John.

Analyst: Hey. Good morning, everyone. Thank you for the time. 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 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 outlined in the fundamentals update a couple weeks ago?

Maybe just kinda walk us through the kind of macro behind the '27 piece.

Randy Fowler: Yeah. John, this is Randy. I appreciate the question. Yeah. Really, what we were looking at when we saw the potential for 2027 was really just fee-based EBITDA growth. 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. So, really, the driver was fee-based cash flows off new assets going into service and around the acquisition that we did from Occidental Petroleum, that you'd start seeing those volumes show up on our system at the beginning of 2027. Those are really the drivers.

Analyst: I appreciate that. That's clear. Thank you. And 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?

Tug: Yeah. This is Tug. You're seeing strong physical premiums, for example, in dated Brent, but 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.

Analyst: 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 clear resolution in the Strait?

Tug: It sure looks like it. It looks like it.

Analyst: Appreciate the time. Thank you.

Jim Teague: Thank you.

Operator: Our next question comes from the line of Gabe Daoud of Truist. Your line is open, Gabe.

Analyst: Thanks, operator. Good morning, everyone. Thanks for the time. I was hoping maybe to just touch on the gas side just for a second. Maybe Haynesville gathering. Is there—in the shoulder season now and front month at 2.50—we'll see what happens in the summer, but curious if you're seeing any change in behavior. It does seem like privates build productive capacity to turn on at the appropriate price signal, but curious if you're seeing any change in behavior.

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

Analyst: Alright, Natalie. Got it. Thanks, Natalie. And just a quick maybe shifting back to the Permian as the commercial team tends to win some new business, obviously, basin-wide. But just curious what's most important to producers today? Is it reliability, just given where pricing is; fees; maybe differentiation given your sour gas capabilities? Just trying to frame the competitive dynamics today. Thanks, guys.

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

Tyler Cott: I'll just—this is Tyler—I'll just add that Natalie operates a super system out there, which provides our customers a lot of reliability.

Analyst: Yep. Understood. Now that makes sense. Thanks, everyone.

Jim Teague: Thank you.

Operator: Our next question comes from the line of Julien Dumoulin-Smith of Jefferies. Your line is open, Julian.

Analyst: This is Rob Mosca on for Julian. On the CapEx revision and the plan FIDs, I would imagine you'd line of sight to these projects when you issued guidance last quarter. Should we interpret this to mean that incremental FIDs, like a new frac, bias 2026 CapEx higher? And is what you have now actually a pretty firm number? And also, maybe if you could provide an update on those commercial agreements you spoke to with Exxon last quarter. Thanks.

Randy Fowler: Yeah. The first part of your question, no, our CapEx guide does include anticipated projects that are under development. 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 two processing plants that we just announced with the earnings release this morning—we actually had the long lead items associated with that plant in our guide, just did not know when we were gonna come in and actually FID those. And the FID, again, just with the volume growth we've seen in the Permian, came earlier.

So that was, if you would, the reason for the increase in the CapEx guide for this year because we'll see some of that CapEx happening late this year.

Zach Stray: And this is Zach Stray. On the NGL side, on the fractionation side, you know, Natalie mentioned she's probably up on the upper end of her guidance. So always looking at building fractionators. We'd like to bring on fractionators full; helps the economics. We've got a lot of levers within the system. Honestly, we were probably a little late on 14, but we got a lot of levers. So we'll see if we need another fractionator. And if we do, we'll build one. Not sure what your question is on the Exxon side.

But on the downstream agreements I would say that we talked about, I would say a lot of those agreements were just extensions of deals that we already had, and it was just a natural fit while we were in the conversations about Bahia to go ahead and extend those contracts.

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

Tyler Cott: 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. And I think as we've said before, we expect NRT to do a good amount of propane in the balance of this year, and that will transition to ethane as our EHT capacity comes online late this year.

Analyst: Alright. Appreciate the time, everyone.

Operator: Our next question comes from the line of AJ O'Donnell of TPH. Please go ahead, AJ.

Analyst: 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 US Gulf Coast have been as high as 55¢. I'm just wondering, given that Phase two 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.

Tyler Cott: 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. And so we'll respond to what products the markets need and have the highest value with the spot capacity that we have available, those products being ethylene, propylene, LPG, and ethane.

Analyst: Okay. Great. Then I just had one more. On the crude business, looking at the Q1 results, could you provide a little bit more detail on 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?

Jay Bainey: Yeah. AJ, this is Jay again. You know, in Q1 results, we had a headwind with the Eagle Ford JV renegotiation on some fees there, and then some mark-to-[inaudible] noise. Lower spreads. But you brought up looking forward—the spreads increased, and 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.

Analyst: Okay. Thank you very much.

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

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

Jim Teague: What we hear from producers is they're gonna stay disciplined.

Natalie Gayden: I think that's true. I mean, they'll stay disciplined. We'll 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. So that's what we're seeing.

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

Tug: Nope. This is Tug. I don't think it's necessarily a specific price. It's probably more focused on the back of the curve being lifted up, and not just next year. It needs to get lifted up from when you're on that.

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

Unknown Speaker: Oh—

Natalie Gayden: For 2026?

Randy Fowler: Jeremy, that's getting pretty granular.

Analyst: 2027 works as well. Thank you.

Randy Fowler: Probably for 2027, I would say probably half of 2027 is not spoken for.

Analyst: Yeah. That's very helpful.

Randy Fowler: Yeah. Thank you. Somewhere between 50–65%.

Unknown Speaker: Thank you.

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

Analyst: Hi. Good morning. I wanted to clarify on Neches River Phase 2. Would you have contracted any of the LPG shipments on that since it's only an interim service until you switch to ethane? Or is that all spot? And then just wanna confirm the timeline you would switch to ethane. You're required to do that at year-end?

Tyler Cott: We do have propane contracts that will be ramping up here at NRT on the flex train. And then as EHT comes online, we'll satisfy contract demand long term at EHT. Ethane commitments are generally driven by when the VLECs arrive; largely, that's later this year and into next year.

Analyst: 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 Teague: Frankly, I think ethane has surprised me. The appetite for it—I could see that growing. And another one is we're gonna ship out what, Chris? 3 million barrels of ethylene this month?

Chris: That's right, Jim. Yeah. Our ethylene exports over the last couple of months have been really high.

Jim Teague: 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. And I think I'd like to see that grow. We've got our own targets for where we'd like to be. I'm not gonna share, but I like the broadening of the offerings other than a specific project.

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

Jim Teague: Yeah. A healthy petrochemical business is good for Enterprise. And they were running pretty strong before this. What's changed—some are making a heck of a lot of money. Thank you.

Unknown Speaker: Thank you.

Operator: Our next question comes from the line of Jason Gabelman of TD Cowen. Please go ahead, Jason.

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

Jim Teague: And we just now are coming out of a turnaround on our Oleflex unit, and so we're not able to get full capacity.

Unknown Speaker: But if—

Jim Teague: But we're coming out of that, and we think it's gonna be strong through the quarter.

Analyst: Got it. That was it for me. Thanks for the question.

Operator: Thank you. I would now like to turn the conference back to Joe Theriak for closing remarks. Sir?

Joe Theriak: Thanks, Latif, and thank you to our participants for joining us today. That concludes our remarks. Have a good day.

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

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