Enterprise Products Partners L.P. (NYSE:EPD) Q2 2025 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q2 2025 Earnings Call Transcript July 28, 2025

Enterprise Products Partners L.P. beats earnings expectations. Reported EPS is $0.66, expectations were $0.642.

Operator: Thank you for standing by, and welcome to Enterprise Products Partners LP Second Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to hand the call over to Libby Strait, Vice President of Investor Relations. Please go ahead.

Libby Strait: Good morning, and welcome to the Enterprise Products Partners conference call to discuss second quarter 2025 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward- looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

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

A. James Teague: Thank you, Libby. Despite facing considerable headwinds, we delivered another good performance this quarter. Seasonally, the second quarter is always tough. But this time, we also face macroeconomic and geopolitical challenges. Today, we reported adjusted EBITDA of $2.4 billion, $1.9 billion of distributable cash flow, providing 1.6x coverage, and we retained $740 million of DCF. We set 5 volumetric records for the quarter, processed 7.8 billion cubic feet of natural gas per day, moved 20 billion cubic feet per day through our natural gas pipeline network. We transported over 1 million barrels per day of refined products and petrochemicals. And we have even more plant, pipe, frac and dock capacity coming online over the next 18 months.

We’ve got nearly $6 billion worth of organic growth projects entering service. That includes 2 gas processing plants in the Permian that are ramping as we speak and a third plant that is expected to start up in the first part of next year. Altogether, these 3 plants will bring our total Permian processing capacity to almost to almost 5 Bcf a day, producing 650,000 barrels a day of liquids. In the fourth quarter, we expect to start up the 600,000 barrel per day Bahia Y-grade pipeline and our Frac 14. These investments bring more volumes into our NGL value chain. We started operations at our Neches River terminal. Initially, the facility will have the capacity to load ethane at 120,000 barrels a day. In the first half of 2026, the facility will be fully operational with the commissioning of a second train that is a flex train.

This expansion will increase its capacity by an additional 180,000 barrels a day of ethane or 360,000 barrels a day of propane. This past quarter was dominated by headlines about tariffs and trade, many of this being close to home, especially regarding ethane and LPG. We managed to navigate these disruptions. That said, we’ve been clear about the risk of weaponizing U.S. energy exports. These kind of actions rarely hurt the intended target and often backfire hurting our own industry more. We’re fortunate this administration understands the importance of energy and global trade even if the Commerce Department may need a little reminder. Unfortunately, we could face similar challenges in the future. There are growing rumors of midstream companies planning to enter the LPG export market.

However, this space has become increasingly competitive and the impact is already evident. Just a year ago, spot terminal fees range from $0.10 to $0.15 per gallon. That is no longer the case. In the second quarter, our LPG export volumes rose by 5 million barrels quarter-to-quarter, yet our gross operating margin declined by $37 million. This was driven by the recontracting of a legacy 10-year double-digit term agreement, the current market pricing and by a 60% drop in spot rates. Although increased throughput across our Houston Ship Channel Pipeline System helped mitigate the decline, it doesn’t change the fact that this market is fundamentally shifting. Despite the challenges, however, we remain well positioned to succeed. Our competitive advantage from our existing export infrastructure enables us to meet customer needs through brownfield expansions where new build economics simply don’t work, and we will aggressively defend our position.

The appetite for U.S. ethane and ethylene remains strong in both Asia and Europe. As to octane enhancement, we’ve seen margins normalize after a few years of outsized earnings, but the business remains healthy. Lower margins are a product of new supply in the market, not waning demand. Hydrocarbons is a supply-driven business, and our network of assets reflect that. The majority of our capital projects currently under construction directly support our supply strategy, but supply isn’t the whole story. What sets us apart is our extensive connectivity to end users. We are directly or indirectly linked to 100% of the ethylene plants in the U.S. and 90% of the refineries east of the Rockies. Our export business continues to be a key part of our strategy.

With the addition of the Neches River terminal, expanded LPG loading at EHT and increased ethylene export capability at Morgan’s Point. We’ve taken deliberate steps to enhance and expand our downstream footprint, strengthening our access to global markets. And with that, Randy, I’ll turn it over to you.

W. Randall Fowler: Okay. Thank you, Jim. Good morning, everyone. Starting with the income statement. Net income attributable to common unitholders were $1.4 billion for both the second quarters of 2025 and 2024. Net income to common unitholders on a per unit basis increased 3% to $0.66 per common unit in the second quarter of 2025 compared to $0.64 per common unit for the second quarter of last year, both on a fully diluted basis. Adjusted cash flow from operations, that is cash flow from operations before changes in working capital was $2.1 billion for both the second quarters of 2025 and 2024. Distributable cash flow increased $127 million or 7% to $1.9 billion for the second quarter of 2025, primarily due to lower sustaining capital expenditures compared to last year that had a higher level due to modifications and a turnaround at PDH 1.

Distributable cash flow provided 1.6x coverage of the distribution declared for the second quarter this year, and Enterprise retained $748 million of distributable cash flow. For the last 12 months, the partnership has retained $3.4 billion of distributable cash flow. We declared a distribution of $0.545 per common unit for the second quarter of 2025, which is a 3.8% increase over the distribution declared for the second quarter of 2024. The distribution will be paid August 14 to common unitholders of record as of the close of business on July 31. In the second quarter, the partnership purchased approximately 3.6 million common units off the open market for $110 million. Total repurchases for the 12 months ended June 30, 2025, were $309 million or approximately 10 million common units, bringing total purchases under our $2 billion buyback program to approximately $1.3 billion.

In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 5.5 million common units on the open market for $171 million during the last 12 months, including 1.3 million common units on the open market for $41 million during the second quarter of 2025. I’ve highlighted on past calls that almost 50% of our employees participate in the employee unit purchase plan. We did some analysis using our 2024 K-1s. At December 31, 2024, as a group, our employees, retirees and their families owned over 40 million EPD units or almost 2% of outstanding units and made them our second largest unitholder after privately held EPCO at year-end. For the 12 months ending June 30, 2025, Enterprise paid out approximately $4.6 billion in distributions to limited partners.

Combined with $309 million of common unit repurchases over the same period, Enterprise’s total capital return was $4.9 billion, resulting in a payout ratio of adjusted cash flow from operations of 57%. Total capital investments in the second quarter of 2025 were $1.3 billion, which included $1.2 billion for growth capital projects and $117 million of sustaining capital expenditures. Our expected range of growth capital expenditures for 2025 and 2026 remain unchanged at $4 billion to $4.5 billion for 2025 and $2 billion to $2.5 billion for 2026. We continue to expect 2025 sustaining capital expenditures to be approximately $525 million. Our total debt principal outstanding was approximately $33.1 billion as of June 30, 2025. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio was approximately 18 years.

Our weighted average cost of debt was 4.7% and approximately 98% of our debt was fixed rate. At June 30, 2025, our consolidated liquidity was approximately $5.1 billion, including availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA for the second quarter was $2.4 billion and for the last 12 months was $9.9 billion. As of June 30, 2025, our consolidated leverage was 3.1x on a net basis after adjusting our debt for the partial equity treatment of our hybrid debt and reduced by the partnership’s unrestricted cash on hand. Our leverage target remains at 3x, plus or minus 0.25 turns. With that, Libby, I think we can open it up for questions.

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

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Spiro Dounis of Citi.

Spiro Michael Dounis: First question, I just want to maybe take a look at second half of ’25. Jim, you mentioned about $6 billion of assets coming online in the second half. Just curious, how should we think about the ramp-up of those assets? Are there a lot of volumes behind the systems? Should we expect these processing plants to come online pretty full as well?

A. James Teague: Zach, what would be your ramp-up on 14?

Zachary S. Strait: Frac 14 will come up completely full. NRT will see a ramp as VLECs are ordered and Natalie can chime in, but I think the processing plants are going to have a pretty quick ramp to them as well.

Natalie K. Gayden: Yes, that’s right. And Delaware and Midland combined is probably around a 90% utilization today. But remember, we just brought those 2 plants up — by the end of the year, fourth quarter mainly driven, Delaware should be full and [indiscernible].

A. James Teague: Will Bahia come up at just?

Michael C. Hanley: Bahia should come up probably around 50% first 12 months, probably closer to 60%. Again, that’s middle of fourth quarter start-up, so you won’t get a full quarter’s contribution until the first quarter of next year.

Spiro Michael Dounis: Got it. Got it. All very helpful. Second question, maybe just shifting to capital allocation. Stepped up the buyback a little bit this quarter. I imagine that was in response to just some volatility in the price. But as we sort of look forward, you’re still sort of holding on to that $2 billion to $2.5 billion for 2026. So I wonder now as we’re approaching that time frame, do you start ratcheting up the buyback in anticipation of 2026 being a lean year? Or really not until we get into it, do we see any sort of, let’s call it, step change in the buyback program?

W. Randall Fowler: Spiro, this is Randy. We had said actually last quarter that our expectation this year was we would probably do anywhere from $200 million to $300 million of buybacks. You’re right, in the second quarter, we did see some volatility. And so we picked up the pace of purchases. And I think we’ll continue to be opportunistic for the remainder of this year. I think the larger opportunity for the buybacks will come in 2026 as we really start throwing off much more free cash flow.

Operator: Our next question comes from the line of Jean Ann Salisbury of BofA.

Jean Ann Salisbury: I wanted to go back to some of Jim’s commentary on the call. LPG export fees have fallen. Pipeline and frac might be overbuilt as well and have some pressure there. How do you see this evolving? And how will Enterprise balance defending market share with kind of maintaining your excellent return on capital?

Michael C. Hanley: Jean Ann, this is TUG. So it’s — from our perspective on specifically on LPGs, we stand 85% to 90% contracted through the balance of the decade. And as far as our strategy, we’re all using brownfield economics over here. It’s all bolt-on infrastructure. So it allows us to be extremely competitive to continue to get term contracts, which we continue to sign up additional counterparties, and we’ll continue to do so.

A. James Teague: Jean Ann, the other thing I think is important is that export facility has a way of being a magnet for our pipelines and our fractionators and our storage.

Jean Ann Salisbury: That makes sense. And then I think as my follow-up, it’s probably for Tony. There’s obviously a lot of concern about potentially slowing oil growth in the Permian next year. If oil growth does slow down or even is flat next year, do you see the rate of gas-to-oil ratio growth changing, if at all? And how do you think about that?

Anthony C. Chovanec: I think, thinking about that question, first and foremost, we believe the Permian Basin producers have been and will always be looking for oil. That said, they’ve been drilling about 5,000 locations a year for the last several years. So I would say it’s clear that the easiest and oiliest locations for the most part, have been drilled up. Thus, we have been and we will be drilling gassier benches, and we’ve talked about that for the last year or 2. You add to that, that oil naturally declines faster than natural gas does. And we have this very large PDP and very large and growing PDP base in the Permian. So Jean Ann, in any way you cut it, all signs point to the Permian Basin continuing to get gassier really for years to come. There’s no question about it. I think while we’re on the topic of the Permian, maybe I’ll just talk about how we see the Permian, if maybe this is a good time to talk about it. Because there’s been a lot of — what’s that?

Jean Ann Salisbury: It’s a great time, Tony.

Anthony C. Chovanec: Okay. There’s a lot of that’s happened over the last 60 to 90 days. First and foremost, OPEC has abandoned their long-standing market stability role in favor of market share and on the way to putting a couple of — 2 million barrels of incremental production on in just a 6-month time period, that’s a lot. And then we had the Israel and Iran conflict break out to a full-fledged war. And all the oil facilities in Iran and throughout the Middle East were unscathed. So thus, we had the war premium taken out. So while all that being said, there’s a lot of pressure one could see on oil. Meanwhile, we’re sitting here in summer driving season around the world and strong demand in the Middle East. So the question is when this strong demand ends, summer driving season ends and Middle East quits using all the oil for electrical generation, what happens to oil.

And I guess, Jean Ann, respectfully, I see there’s a lot of people that are — that have some pretty dire forecast. And we feel differently. And I think I’ll just point out the reason we feel differently is OPEC has been shorting the market at least 2 million barrels a day for 2 years running and more on top of that. So there is a massive hold to be able to put oil into when and if the price drops. So assuming we have a price drop and we move from backwardation to contango, oil is going to get a signal to trade into storage, and that’s the way we see it. So we’re probably not as bearish on price, although we don’t have to call price, we’re not as bearish as others. But from a fundamental standpoint, I will say, we’re not as bearish as others.

So what does that mean for U.S. producers? We had a brief period where we touched $57. But we’re at $65 this morning. And really, when you look at ’26, ’27 all the way up to $30, we’re at $62 to $63. For the Permian producer, which is where we’re focused with our assets, you add the improvement in gas basis because in new pipelines to take away. And really, Jean Ann, Permian producers’ bottom line is extremely profitable. So I think what we’re going to see during earnings season for producers is you’re going to see them hold their guidance and not go down. Where others are saying the Permian is going to be flat to down. We just don’t believe that’s going to happen. you’ll see them hold their guidance for the year, and you’ll see that they’ve been aggressively hedging ’25, ’26 and maybe even some of them ’27.

From a fundamental standpoint, that’s how we see it. Natalie, what are you seeing? Are we?

Natalie K. Gayden: Yes. We are not hearing anything different than what we spoke to in our last earnings call. We actually did get a surprise from one of our producers who brought wells forward in 2026 in their production plans. There are a few production areas, too, in our portfolio where it’s not declining as expected. And I’ll just leave you with this. In Midland, this year, we will have brought on 463 wells. Next year, we are — we will — we have 498 on the schedule, just to give you some color.

Anthony C. Chovanec: That’s super helpful. You’ve had a really good record at your forecasting. So that carried some light.

Operator: Our next question comes from the line of Theresa Chen of Barclays.

Theresa Chen: I want to go back to the topic of NGL exports. And specifically, what are the lessons learned from the BIS ethane incident during the second quarter? Do you think the views of your customers, suppliers and other stakeholders on U.S. ethane exports to China, do you think those views have structurally changed as a result of this event? And if so, are you likely going to try to find alternate markets or end uses for incremental ethane exports from here?

A. James Teague: TUG, do you want to take it?

Michael C. Hanley: Yes. So if you look at what happened with the BIS requiring export license effectively for ethane, I will say we were largely unscathed at Enterprise, but I’ll remind you that we have a lot of international exposure to other countries other than China, call it, Vietnam, Thailand, India, Europe, Mexico, Brazil. But if it was going to be sustained, I could see it presenting a challenge for ethane structurally here in the U.S. But what it has done and where it’s been a problem is you really compromised the U.S. brand for reliable supply and energy security when you just cut off a counterparty like that. In fact, I will tell you, we had a non-Chinese-based company that we were in discussions with about contracting ethane with.

And they’ve now since made a decision to contract naphtha, which is supplied globally versus just coming to the U.S. to get ethane. So from that perspective, it’s been disruptive. But in the short term, we were able to manage through it with our diverse contract mix.

Theresa Chen: And then within the petchem and Refined Products Services segment, what’s your forward outlook for PDH as well as what is your view for whether it be the second half or into 2026 about the spread-based businesses. Can you touch a little bit on the incremental supply you see in octane that will persist from here?

Christian M. Nelly: Yes. Sure, Theresa. This is Chris. As far as PDHs go, our operating rates have improved quite a bit versus the first quarter. That being said, we’re still not happy and we haven’t met expectations about what our on-stream time should be. As far as our [indiscernible] and octane enhancement goes, we’ve had really a record last 3 years of high margins. And as Jim touched on in the opening remarks, we’ve kind of returned to historic kind of margins. So they’re still really good. I mean, still some of the best margins we have in the company, but it’s not what we have had historically. That being said, so far for the month of July, we’ve seen margins improve just part of that probably being driving season. We still see the pressure from China.

Historically, MTBE was more of a regionally regional market where occasionally, you would see some cargoes coming from Europe or from Asia. And occasionally, we would send some cargoes to Europe or Asia. But by and large, it was regional. That’s changed with all the additional capacity coming on from China, and we started seeing that pressure. And that’s some of the reason why we’ve seen some weakness.

Operator: Our next question comes from John Mackay of Goldman Sachs.

John Ross Mackay: I want to go back to the margin compression conversation. I think the narrative around the LPG exports hub is clear. I guess if you could just comment where do you stand in that process for repricing down those LPG exports? Is that kind of in there now? Or is there maybe a little bit more to work through? And then maybe any comment you can make on a related side for anywhere else in the portfolio, particularly the Permian NGL pipes?

Anthony C. Chovanec: I’ll take it and then TUG, you can take it.

A. James Teague: I think you heard TUG say we’re 85%, 90% contracted on LPG exports through the end of the decade. We’re going to be full here and simple, and we’ll defend it ever how we have to. And TUG, you got anything to add other than [indiscernible] going to be full?

Michael C. Hanley: No, we’re full. We are full. We’re going to continue to contract full, but I’ll just tell you that we’re still executing contracts. So whatever we’re going to lose on margin compression, we’re going to make up by volume.

John Ross Mackay: And then just anything you can add on the Permian NGL pipe side?

Justin M. Kleiderer: Yes, John, this is Justin. I would say, generally on [indiscernible], we have very little recontracting to work through to the balance of the decade. At our core, we still expect production to grow. So long as supply growth is happening, we don’t expect recontracting to play a role because we’re going to continue to see volumes increase.

Operator: Next question from Michael Blum of Wells Fargo.

Michael Jacob Blum: Can you hear me?

Operator: Yes, sir. Please proceed.

Michael Jacob Blum: I’ve been reading a little bit about potentially an uptick in activity in the San Juan Basin. I’m just wondering if there’s much to that. Are you seeing anything different from your producer customers up there? And could that have a meaningful impact for you guys?

A. James Teague: Natalie?

Natalie K. Gayden: Not necessarily where we are located. I guess the uptick in activity, I don’t know if you’re talking about the recent acquisition of a player there. But as far as we can tell, our San Juan is pretty stable, flat to slight, really small growth.

Michael Jacob Blum: Okay. Great. I appreciate that. And then just maybe just a follow-up for Tony. I appreciate all the commentary. Is it fair to say, if I think back to your — I think it was like April 1 updated production forecast that if you had to tweak that today, there would be pretty minor tweaks to what you were seeing back in April?

Anthony C. Chovanec: Michael, that’s a great question. I really appreciate it. Yes. There — if we had to tweak it today, given the profitability of the Permian producer, those tweaks would be small. So from a black oil standpoint, we were calling for ’25 through ’27. I think we were calling for 800,000 barrels of growth. Could that be 7? Yes, certainly, it could. If prices did go through a low spot, if we had a fall in prices and we go into contango and then waiting for people to start storing, could that be a growth of 6%? I guess on the outside, it could. Look, we think we grew 350 last year. So when producers talk about their guidance as we all listen to their calls coming, Michael, and they say they’re going to stick to their guidance and their guidance was 3% to 5% growth in the Permian as a general rule.

It’s not hard math. It’s I think we’re on target, Michael. I think we’re on target. And we’ve said before that liquids forecast is on target to meet our forecast or producers continue to drill gas here. So we feel great about our liquids forecast also. And then Natalie has confirmed and Justin is confirmed, Zach has confirmed, that’s what we’re seeing in the business. We’re not a sky is falling scenario. Look, the Permian producer is extremely profitable, especially when you look at what’s happened to natural gas basis out there.

Operator: Our next question comes from the line of Manav Gupta of UBS.

Manav Gupta: There are a lot of announcements on potential LNG projects, and there is a belief that Haynesville Shale could be supplying some of them. Can you talk about your leverage to the Haynesville Shale, maybe talk about the Acadian Gas system a little.

Natalie K. Gayden: So our Acadian Gas System, we actually went out for open season on our recontracting efforts on that pipeline, actually, timing is everything and came up at the right time. So the rates we’re going to achieve on that pipe relative to historical is 2x to 3x what we’ve seen before. So a little bit more increase in activity, obviously, in the Haynesville with price of gas, and we’ll reap benefits from that.

Manav Gupta: Okay. And quickly, since your CapEx is dropping, can you talk about the criteria you could possibly look at for possible bolt-on opportunities as a company?

W. Randall Fowler: Yes. No, I think when we came in and sort of gave future guidance of $2 billion to $2.5 billion, that’s really taken into consideration some organic growth that we could see in our system in the coming years, whether it’s additional processing plants in the Permian or something more on the distribution side of the downstream part of our system.

Operator: Our next question comes from the line of Keith Stanley of Wolfe Research.

Keith T. Stanley: I want to clarify some of the earlier questions around LPG exports. So you’re 85% to 90% contracted through the end of the decade. Given that, is it fair to assume the more meaningful recontracting headwinds on margins are now over with at this point?

Michael C. Hanley: This is TUG. That is correct.

Keith T. Stanley: Okay. Great. And then I had one on Neches River. So the major projects under construction bucket went down $2 billion from $7.6 billion to $5.6 billion. It looks like that’s 2 processing plants and Phase 1 of the export facility. That implies the capital cost could be maybe $1 billion or more for Phase 1 of Neches River. Am I thinking about that right just as a ballpark?

Michael C. Hanley: Yes. That’s in the ballpark.

Keith T. Stanley: Okay. And would Phase 2 be similar to that?

Michael C. Hanley: Not that much.

Operator: Our next question comes from the line of Brandon Bingham of Scotiabank.

Brandon B. Bingham: I’d like to go back to capital allocation, if we could, and maybe ask on the inorganic side in a different way. Just given all of the cash gen that you guys have and you have your priorities outlined pretty clearly, would you consider maybe increasing activity and equity investments potentially into areas where you currently do not participate or operate any assets maybe like in LNG? Or just how should we think about all of the cash gen moving forward?

A. James Teague: I imagine Randy is going to try to give it to you guys.

W. Randall Fowler: Yes. Brandon, I don’t see us — and I’m trying to read where you’re going with your question is are you asking would we make passive equity investments in LNG facilities?

Brandon B. Bingham: Right. Like taking a non-op stake or an equity interest or just another way to deploy capital that maybe hasn’t been discussed?

W. Randall Fowler: No. Yes.

Brandon B. Bingham: Fair enough. And then maybe just on 2026 growth spend, could you remind us how much is currently committed? And then where do you see the most pressing need to deploy capital? Or maybe asked another way, where is the greatest opportunity across your operations right now?

A. James Teague: Yes. I think when we look at that in 2026, that range of $2 billion to $2.5 billion, what’s committed is approximately $2.2 billion. And where we go? I really like what we’ve done in terms of our ethylene. If I look back a few years, we didn’t have anything in ethylene. Now we’ve got a pretty robust storage distribution and export system. And those fees are cents per pound, not cents per gallon.

Operator: Our next question comes from the line of Jason Gabelman of TD Cowen.

Jason Daniel Gabelman: I’m afraid I’m going to ask another one on LPG exports and trying to understand it more from a strategic standpoint, given the amount of build-out that the industry is pursuing on LPG exports. Have your upstream customers kind of told you that you need to more or less have that egress to compete for additional volumes from them. So is this LPG export build kind of driven by what the customer needs and to keep you competitive in contracting with those customers?

Michael C. Hanley: I can’t — this is TUG. I can’t speak for what our competitors are doing relative to their CapEx or how much it costs them to build these greenfield facilities. I can just tell you the success we’ve had on contracting with our brownfield economics it’s there. You have to remind yourself as well that Enterprise Mont Belvieu is the pricing point for, call it, over 95% of total NGL production in the United States. That’s another competitive advantage we have. And our customers are there to continue to take the LPG exports from our facility at a competitive fee.

A. James Teague: I think it’s worth noting that we’ve been dealing in the international market since 1983 when we put in an import facility and since 1999 when we built our export facility. We’ve created a lot of strong relationships, and we’ve performed. So I don’t think — I think we’ve got a rather sticky customer base tied to what we’ve been able to do in the past.

Jason Daniel Gabelman: Okay. And my follow-up is, unfortunately, a topic that has also been already asked on, which is capital allocation. And I guess the question is the midstream sector broadly has had multiple expansion given all of the growth opportunities that they’ve been pursuing over the past couple of years. And as you think about capital allocation moving forward, how important is it to continue to have a robust growth backlog that really competes with other companies in the industry to continue to attract equity investment? And how much does that kind of frame your strategic decisions on capital allocation moving forward?

A. James Teague: Do you want to take it?

W. Randall Fowler: Yes. Let me I think, first, we feel like we’re in a good place, the basins that we operate in, focus on the Permian, focus on the Haynesville, the sectors that we support, the downstream sectors, petchem is a little soft right now. But again, they’ll cycle through this. So we like our footprint. We like where we are. We think we’ll have bolt-on opportunities from an organic standpoint and inorganic standpoint as opportunities arise. When you come back in, especially look over the last 2024 and 2025, our CapEx did step up, but a lot of that was a step change in capacity to be able to come in and be able to support the growth of our E&P customers coming out of the Permian. So I think we’re in good shape there.

I think we’ve got some low-cost expansions that we can do on some of those assets that are coming into service. And we’re here for the next couple of years anyway at that $2 billion, $2.5 billion, our job is to keep our system reliable, keep it up, and we should throw off a lot of cash flow from those businesses. And where we see opportunities to deploy it, we will. But honestly, I think discretionary free cash flow is really about to take a step up in 2026, 2027, and that will give us an opportunity to come and return more capital to our investors.

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

Libby Strait: 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.