Enterprise Products Partners L.P. (NYSE:EPD) Q2 2024 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q2 2024 Earnings Call Transcript July 30, 2024

Enterprise Products Partners L.P. misses on earnings expectations. Reported EPS is $0.64 EPS, expectations were $0.661.

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

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

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

Jim Teague: Thank you, Libby. We had another solid quarter, both in terms of volume and cash flow. We reported adjusted EBITDA of $2.4 billion compared to $2.2 billion in the same quarter last year. We generated $1.8 billion of distributable cash flow. We had 1.6 times coverage for the quarter. We retained $661 million of DCF in the second quarter, and we’re at $1.5 billion year-to-date. Even though the second quarter can be seasonally our weakest quarter, our company handled a near record 12.6 million barrels per day of crude oil equivalent volumes and 2.2 million barrels a day of marine terminal volumes as well as record natural gas processing and record NGL pipeline and fractionation volumes. Our investments to support growth in the Permian Basin are visible, both volumetrically and financially in our NGL Pipeline and Services segment, which reported a 19% increase in gross operating margin compared to the second quarter of last year, primarily attributable to our four new natural gas processing plants in the Permian and our 12th NGL fractionator at our Mont Belvieu area complex.

In addition, we also benefited from improvements in natural gas processing margins compared to last year. Our Natural Gas Pipelines & Services segment also reported a 23% increase in gross operating margin compared to the same quarter in 2023. This increase was primarily driven by higher transportation revenues and higher marketing margins, associated with the wider spreads between op and higher valued market hubs. We had a very good quarter in spite of the challenges of our PDH plants. They have been somewhat of a headwind throughout the year. We recently completed our turnaround at PDH 1. Planning for the turnaround took over a year and involved a dedicated turnaround team in addition to field engineering and maintenance personnel. This team documented every issue we’ve had with this plant and developed solutions for each one.

The turnaround took 100 days. A few factoids, turnaround was over 1.25 million hours worked. At the peak, we had 1,250 people per shift. We had 590 work packages executed, 17 million pounds of catalysts handled 1,465 crane lifts, 190 18-wheeler deliveries, 52,800 bricks and inspected over 41,000 replaced. Those bricks are the catalyst support and the catalyst reactor. The plan is now up and running and exceeding its nameplate. PDH 2 is currently in turnaround. We expect it to be producing PGP sometime around mid-August. The PDH 2 turnaround is not nearly as involved as PDH 1. I’d like to thank our Mont Belvieu team and our supporting service providers for their long hours and hard work during these back-to-back turnarounds. We’re confident that these two plants will be a tailwind the rest of the year.

We also completed our diluent open season on the TE product system. We closed the open season with 100,000 barrels a day of new and reach contracted commitments, and I think those are five-year deals. We then accommodate — we can accommodate this incremental demand with the suite of debottlenecks and horsepower additions, while ensuring we do not impact our existing customers. Finally, our company has $6.7 billion of projects under construction that provide visibility to future earnings and cash flow growth. These projects include three processing plants, one in the Midland Basin, two in the Delaware and associated gathering. Our Bahia NGL pipeline, frac 14 and export expansions at the Neches River Terminal in the ship channel. All of these projects are backed by long-term contracts and significantly enhance what is already a very strong NGL value chain.

And as has been the case for several years running, we continue to see even more rich gas volumes coming from the Permian than we had previously forecasted. And Tony may have something on this in the Q&A. And with that, I’ll turn it over to Randy.

Randy Fowler: All right. Thank you, Jim. Good morning everyone. Starting with the income statement. Net income attributable to common unitholders was $1.4 billion or $0.64 per unit for the second quarter of 2024. This was a 12% increase over the second quarter of 2023. Our adjusted cash flow from operations, which is cash flow from operating activities on the cash flow statement before changes in working capital, this number increased 11% to $2.1 billion for the second quarter of 2024 compared to $1.9 billion for the second quarter of last year. We declared a distribution of $0.525 per common unit for the second quarter of 2024. This is a 5% increase over the distribution declared for the second quarter last year. The distribution will be paid on August 14th to common unitholders of record as of the close of business tomorrow, July 31st.

In the second quarter, the partnership purchased approximately 1.4 million common units of the open market for $40 million. Total purchases for the 12 months ending June 30, 2024, were $176 million or approximately 6.5 million Enterprise common units. And this brings total repurchases under our buyback program to approximately $1 billion or about 50% of the total program amount. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 6.3 million common units on the open market for $171 million during the last 12 months, including 1.8 million common units on the open market for $50 million during the second quarter of 2024. For the 12 months ending June 30, 2024, Enterprise paid out $4.4 billion in distributions to limited partners combined with the $176 million of common unit purchases over the same period, Enterprise’s payout ratio of adjusted cash flow from operations was 55%.

Total capital investments in the second quarter of 2024 were $1.3 billion, which included $1 billion for growth capital projects and $245 million for sustaining capital expenditures. While our expected growth capital expenditures for 2024 did not change as a result of the LPG export announcement we announced this morning, we did refine the bottom of our range. Our current estimate of growth capital expenditures for 2024 is now in a range of $3.5 billion to $3.75 billion. We continue to expect 2025 growth capital investments to be in the range of $3.25 million to $3.75 billion. 2024 sustaining capital expenditures are elevated due to planned turnarounds for our PDH 1 plant and our iBDH facility and our high-purity isobutylene facility. These turnarounds typically occur every three to four years.

We now estimate 2024 sustaining capital expenditures to be approximately $600 million, up from $550 million, primarily due to higher capital costs associated with the turnaround at the PDH-1 facility, which was completed in June. The turnaround at the PDH 2 facility began in late June 2024 and as Jim noted, we anticipate completion in the middle of August. As of June 30, 2024, our total debt principal outstanding was approximately $30.6 billion. 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 95% of our debt was fixed rate. Our consolidated liquidity was approximately $3.4 billion at the end of the quarter, including availability under our credit facilities and unrestricted cash.

Our adjusted EBITDA was $204 million for the second quarter and $9.7 billion for the 12 months ending June 30, 2024. As of June 2024, our consolidated leverage ratio was 3.0 times on a net basis when adjusted for the partial equity treatment of our hybrids and reduced by the partnership’s unrestricted cash on hand. Our leverage target remains 3.0 times, plus or minus 0.25 times. With that, Libby, I think we can open it up for questions.

Libby Strait: Thank you, Randy. And operator, we are ready to open the call for questions from our participants.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Theresa Chen of Barclays.

Theresa Chen: Morning. Thank you for taking my questions. Maybe starting with the LPG export. So, on that front, you’ve executed and announced multiple expansions with another one just today. Can you just help us think about what inning are we in terms of export expansion buildup for the industry? And across your system, how much more brownfield capacity expansion do you have left?

Tug Hanley: Yes. So, the market is obviously calling for additional capacity. We announced that expansion this morning around, call it, 85% and 90% contracted of our existing and expansion capacity. But as far as our brownfield capacity, we have additional opportunities to execute that. This product was using existing infrastructure, concerning our term contracts we’re out there as highly rates. And like I said, we have additional brownfield opportunities ahead of us.

Theresa Chen: Okay. And Brent, if you can just help us think about like from a commercial perspective, what is the going rate for brownfield expansion across your system, maybe on a per gallon or their unit basis? And how does that compare with greenfield expansion if anyone wants to get into this part of NGL value chain right now?

Tug Hanley: Theresa, this is Tug talking, but I won’t get into a specific rate, but relative to greenfield, it’s significantly more competitive.

Theresa Chen: Okay. Thank you, Tug. And as a follow-up, do you have an update on the commercialization of spot at this point?

Jim Teague: Yes. This is Jim. I’ll take that. Yes, we — up until now, what we’ve been marketing is a concept. And since we’ve gotten our license to construct, we’re marketing a real project now. And we’ve done a heck of a lot of work to determine how competitive we are versus a single lightering and multi-lightering. And if you look at the single lightering, we tracked 563 ships that were single lightering. And out of those 563, we put it into quartiles and we were hands down better than 280 of those and competed very effectively with the first two quartiles. And the multi-lightering, we looked at over 400 million and we beat those hand down across the board. So, if you looked at all the ships we tracked, we track 969 ships and we beat hands down 686 of those ships over that timeframe. So, now we’re going to see if the market wants it.

Theresa Chen: Thank you so much.

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

Michael Blum: Thank you. Good morning everyone. So, I just wanted to go back to the LPG export discussion a little bit. I wonder if you can just refresh us on what you’re seeing for end market demand as you continue to expand capacity? And I guess I’m particularly interested in if you’re seeing a lot of that incremental demand coming from China? Thanks.

Tug Hanley: Yes, this is Tug. So, the demand equation is obviously important to our LPG export expansions. But fundamentally, at the end of the day, the barrel has to clear [ph] to the U.S. and the barrel of price accordingly to do so. With respect to China, right now, our exports stand around 43% going to China, but we’re also around, call it, 21% to the Americas and 13% to Europe. So, we’re seeing a robust demand across the board.

Jim Teague: Tug is that LPG?

Tug Hanley: That’s LPG.

Jim Teague: What percentage of LPG goes to China?

Tug Hanley: Around 43%.

Jim Teague: Propane, butane?

Tug Hanley: Propane, butane.

Jim Teague: Okay. PDH plans. Okay.

Michael Blum: Great. No, I appreciate that. And then I just wanted to revisit in the capital allocation discussion around buybacks. I think we all understand at this point that enterprise, your definitely preferred method of returning cash in distribution growth over buybacks. So, I’m wondering if you can just refresh us on the criteria where you decide to allocate capital to buybacks especially given that it seems like you have a pretty nice slate of organic growth opportunities at attractive returns? Thanks.

Randy Fowler: Yes, Michael, this is Randy. Yes, Mike, what we’ve been targeting over the last few years, and 2024 is not that different, is probably coming in and doing buybacks in the $200 million range. And what that’s done is we do issue equity as a component of compensation. But when you come in and take a look at what we issue in terms of compensation and what we buy back, you’ll see over the last four years, there is a decrease in the number of overall units outstanding. So, I think that’s our focus. Once we get back out — this year and next year, again, we’re talking this year, growth capital expenditures in the $3.5 billion to $3.75 billion range, growth CapEx. Next year, we’re still estimating at $3.25 million to $375 million.

That’s probably going to keep those buybacks in that $200 million range. Once we get back out to 2026, there, we’re thinking growth CapEx could be, call it, around $2.5 billion. Then I think we have more room to return capital. And then I think we really just need to get some visibility on 2026 to see what form that increase in the return of capital would look like as far as distributions and buybacks.

Michael Blum: Great. Thanks Randy.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet of JPMorgan.

Jeremy Tonet: Hi, good morning. Hello good morning.

Randy Fowler: Good morning Jeremy.

Jeremy Tonet: Just wanted to make sure you could hear me there. Thank you. Just wanted to see, I guess, there’s been — some of your midstream peers out there have been acquiring assets, there’s been some bolt-ons. And I just wanted to at your thoughts about Enterprise’s role within industry consolidation at this point? And I wanted to see, I guess, any thoughts you could share on that at this point, this is the last major wave of consolidation in midstream?

Randy Fowler: Okay, Jeremy, I’ll take the first crack of that. And from a strategic standpoint, I’ll let Jim comment. But I think our — first and foremost, what we’re looking at is returns on capital and what gives us the best returns on capital and growing cash flow per unit because at the end of the day, that’s what’s going to drive value. And we’ve taken a look at a number of opportunities, more asset acquisitions than, I would say, public company M&A. But what we’ve seen thus far is organic growth is providing us good opportunities and good returns on capital — relatively better returns on capital and in growing cash flow per unit. Obviously, the Navitas deal that we did, that also provided good returns on capital, good cash flow growth. So, that’s really where our focus is.

Jim Teague: Yes, strategically, I think we’ve always said it kind of has to fit what we already have. And we talked about the plants we’re building in the Permian. I don’t think we’re through building plants. So, it’s got to be — the price has got to be right. It’s got to fit who we are. And when you build a plant, you can put it where it fits who we are. So, I like the organic side, but we look at everything that comes along from a way of more investment bankers come in here, I think you could say, gray so.

Jeremy Tonet: Got it. Makes sense there. Just wanted to also, I guess, get your thoughts as it relates to power in Texas overall, we’ve seen instability in the ERCOT market and other issues out there. I’m just wondering how you feel about that going forward? Could there be room for your own generation or other measures to kind of ensure, I guess, stability?

Graham Bacon: This is Graham, I’ll take that. Yes, certainly, power in Texas can be a challenge and it evolves consistently. We’re doing things with our projects to basically do some hedging of that through purchase of power generation and looking at other options. We work very closely with the power providers and their status and evaluate whether grid power will be acceptable or we need to have other — either backup power or we need to have other power sources available. And each situation is different. Every provider is different, whether you’re working out in the West Texas or East Texas. So, each situation is individual.

Jeremy Tonet: Got it, makes sense. I’ll leave it there. Thank you.

Operator: Thank you. Our next question comes from the line of Tristan Richardson of Scotiabank.

Tristan Richardson: Hi, good morning guys. Just on Bahia, can you give a general update on progress there, maybe how you see utilization ramping as that project comes on? And then maybe just your updated thoughts on a base case for Seminole, based on what you’re seeing on the supply growth side?

Justin Kleiderer: Yes, Tristan, this is Justin Kleiderer. I mean I think updates on Bahia, we’re still on track from a timing perspective. From a commercial perspective, I think go back a couple of quarters from what — how we sort of talked strategically about it, and that is — it’s — the growth is underpinned by our G&P platform, which Jim just spoke to the fact that we don’t think we’re done building plants. So, Bahia be there to catch those volumes. And then when you think about NGL pipelines, you have to also understand the totality of the system that feeds them. And which we have a premier system with all the connectivity to every — a majority of the third-party plants that have supply that can feed the system as well.

So, you really have to look at plant connectivity to really understand what capacity and utilization could look like. And then third, we always have the sort of optionality that all of our pipelines give us in terms of potential conversions and things like that. So, with respect to Seminole, I think it’s a prime candidate for repurposing. I think we’ve been public with that, in which case, if that happens, then those NGLs will feed into Bahia.

Tristan Richardson: Great. Thank you. And then maybe just a clarification question, sorry if I missed this. But could you talk about the EHT expansion announced this morning and the 300,000 today versus maybe what you had talked about previously in that capital side for EHT, I think you guys referred to it as facility upgrades versus an outright expansion. Can you maybe talk a little bit about the distinction there?

Tug Hanley: I mean it’s — so we’re adding an additional refrigeration unit there, expanding the existing dock infrastructure — utilize an existing doctor and pipeline infrastructure that’s ultimately going to 300,000 barrels a day.

Randy Fowler: This is the original project that was on there was more of a flexibility project between different commodities, which this new train ends up providing.

Tristan Richardson: Great. Thank you guys very much. Appreciate it.

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

Spiro Dounis: Thanks operator. Hi team. First question is just on CapEx, but really kind of want to focus on what’s uncommitted at this point. Obviously, spot is a big one, and you mentioned a few times now, the potential for more processing plants get built. But as you think about the rest of the system, you’ve obviously got plenty of pipeline, plenty of export expansion, obviously, some fracs in there. Curious if you could give us a sense of what you think is still missing from that system or maybe areas where customers are coming to you like with this export expansion and demanding more?

Jim Teague: Yes, I remember Dan [ph] one -time, this is Jim, told me we were looking at something and he said, this might be the last deal, Jim. And they keep coming at us. I think we are doing a pretty good job of expanding our primary petrochemical product system, meaning our ethylene system and our propylene system. And I think we’ll be surprised in the years to come, how good we’ll do in that. And I mean I don’t think we have enough export capability based on what I see coming at us in the future. We believe that that rich gas out of the Permian is going to be a couple 3 Bcf a day more than we have forecasted in the past. So, we’re on that export train.

Spiro Dounis: Got you. I guess that does tie to my second question a bit. But just thinking about producers here, curious maybe just one for Tony on how you’re thinking about the outlook or what happens next? But curious if you’ve seen any change in behavior. Obviously, seeing gas kind of turn over here a little bit again, and crude for us has kind of come off the highs. So, are producers acting differently yet? Just curious how you’re seeing maybe in the next, call it, medium term? A – Anthony Chovanec

Anthony Chovanec: Sure, this is Tony. Jim mentioned in his prepared remarks — I guess first of all, we don’t see significant changes in producers. In other words, there is a lot of money on the tables for producers to continue to produce because of price of oil and how profitable they are and frankly, they get more profitable every game. So, while certainly, none of them can like very weak prices at Waha, that doesn’t keep them from putting barrels on the table. Jim in his remarks mentioned that rich gas continues the trend of exceeding both ours and producers’ expectations. What I’d like to add to that is with Natalie’s team, we spend a lot of time with commercial people, producers, and technical people and those meetings with producers, we’re definitely discussing incremental rich gas over and above, frankly, the type curves that we have in our forecast.

I think there’s a number of reasons for this, but to boil it down, I think it boils down to some of the richer gas here, benches now being drilled and planned by producers, especially in the Delaware Basin. Plus some of the GOR increases that we’re predicting, driven by the multi-bench completion methods, whatever you want to call them, that continue to evolve. When we talked about that in our analysts, Natalie always reminds me that we want to be directionally correct in our forecast, no forecast is correct. But without talking to you all about what we’re seeing, again, in these commercial and technical meetings, I think our — from directionally correct, I think we’d be lacking. Jim, I think you mentioned into three incremental Bs. I would say that’s over and above the approximately 30 B of rich gas at 2030 that we had in our forecast.

When you look at a basin producing that much cash, you think, well, that’s not really a big number. But when you consider the fact that it’s liquid-rich and as rich as it is, it gets to be a pretty big number pretty quick. So, that’s the reality of what we’re dealing with. Anybody else want to add anything? Natalie, you agree?

Natalie Gayden: Yes. The only thing I’d add is when you think about that much incremental rich gas and more efficient plants in the basin that are capable of extracting higher ethane than before, it becomes a very quick NGL growth number also. So, one thing that I think has surprised people to the upside is the NGL production out of the basin price is said to do it. So, the capability of the plant and the portfolio of processing plants now there in the Permian just is much greater than passed.

Spiro Dounis: Got it. I’ll leave it there. Thanks as always.

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

Keith Stanley: Hi, good morning. Following up on the Houston LPG export project. Is this a sign that you’re perhaps seeing more demand for Phase 2 at the Neches River project to be all ethane instead of a mix of ethane and propane? And so you have to do the Houston project to accommodate the propane side. And then can you just give an update on how much of the Neches River capacity is contracted at this point on both phases?

Tug Hanley: Sure. This is Tug. So, you’re exactly right. It will maintain the flexibility of the Neches River facility to do LPG. However, as the VLEC order book continues to get delivered out between now and, call it, into 2026, that facility will be in ethane service long-term. As far as the contract level we have on that facility, it is 100% contracted. I will tell you we have additional debottlenecking projects that we can execute fairly capital efficient to get additional capacity there if the market asks for it. We’re in good discussions around that capacity right now and we’ll evaluate if we proceed with that. So, yes, I could see it being ethane long-term. What’s the second question?

Keith Stanley: Great. Thank you. And second question, any — kind of, a technical one, but just any ability for the company to benefit from the wide isobutane to butane spreads that we’ve seen? Or is the focus really still just MTBE to butane?

Jim Teague: We benefit from that spread.

Keith Stanley: From the isobutane to butane?

Jim Teague: Yes.

Keith Stanley: Got it. Thank you.

Operator: Thank you. Our next question comes from the line of John McKay of Goldman Sachs.

John McKay: Hey everyone, good morning. Thanks for the time. I want to go back to, I think, maybe it was Michael’s question on China. We’re seeing, at least, oil demand kind of trending decently below expectations right now. I guess I’d just be curious to hear from your perspective, kind of, where demand is trending overall versus your forecast, your expectations on maybe when that could start to pick up? And maybe just how sensitive your outlook could be to that global demand picture, acknowledging the high contracting level? Thanks.

Tug Hanley: I’ll — this is Tug, I’ll pass it over to Tony. But as far as enterprises exports to China at around 43%, U.S. is around 52%. So, we’re a little bit lower than the U.S. average. I will add that our product does go to China. It’s all indirect. So, we don’t have any direct contract exposure per se on the LPG side. But we are seeing it ramp up quarter-over-quarter. And then Tony, I’ll–

Anthony Chovanec: Yes. If you talk about other liquids demand and Tug is referencing the barrels going to China, that’s — we all know we’ve been watching the build-out of PDHs in China for the last three years, and it’s nothing short of eye-popping. They dominate the olefins market in Asia at this point, especially relative to PDH activity. So, it’s really important in the equation. If you’re also referring to oil demand, I would tell you from our view, there’s nothing wrong with oil demand globally. Probably on track to be growth somewhere between 1.2 million to 1.4 million barrels a day year-on-year. That’s not a bad number, especially with China demand and somewhat weak economies. So, I think other forecasters will tell you the same that that’s about the trajectory we’re on.

Jim Teague: And this is Jim. I don’t think we could undersell the benefits that LPG has with places like Africa and India as a transition fuel from wood and coal. And what we’re seeing is that’s a lot stickier demand and it doesn’t go away.

Anthony Chovanec: In that regard, for those of you who want to search the Internet for Total Energy’s recent commercial that they have been running specifically on LPG in Africa. It’s a pretty moving commercial.

John McKay: I appreciate all that. Thanks. I might push for just one more. I mean, looking ahead to November, tariffs are obviously front of mind. Are those coming up in your commercialization discussions either around kind of incremental NGL sales or maybe on spot?

Tug Hanley: Say the question again? I’m sorry.

Jim Teague: Tariffs, export tariffs.

John McKay: We’re talking about the risk of incremental tariffs starting next year if that’s the impact of commercialization.

Tug Hanley: It gets brought up occasionally, but I’ll tell you the truth. If you were to ask me that question two or three years ago, four years ago, especially is at the later days when Trump was in Office, it was brought up quite often. We’ve been over to Asia a couple of times this year. Those questions and those conversations don’t happen near the frequency that they once did.

Jim Teague: What does happen after the LNG, it cannot depend on the U.S., aren’t you getting some of that?

Tug Hanley: Yes, I mean I think people question in terms of what projects are real and if we’re going to continue to expand the export capabilities of this country. So, I think, obviously, the people that have contracts in place at the incumbent assets, I think, benefit. But in terms of trying to expand anything that they have, especially over in Asia, I think that makes some pause if they can continue to grow and depend on the U.S. But the tariff side, I’ll just expand on that. On the tariff side, I think we fundamentally believe that if the U.S. product has a price to export, then ultimately, the U.S. price has to overcome that tariff based on just pure geography and the transit that they have to incur. So, I mean that’s probably more of a reflection of what the U.S. — what happens to the U.S. price.

John McKay: That’s very clear. I appreciate all the thoughts today. Thank you.

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

Neal Dingmann: Morning all. Thanks for the time. My first question, just — I always appreciate that capital project slide, I’m just wondering something you mentioned earlier kind of got my attention. I just wondered, is it fair to say you won’t spend future CapEx until it’s largely contracted? Or maybe say in another way, wondering if you have an amount that needs to be contracted or percent of volumes that need to be contracted before FID or CapEx spend.

Jim Teague: It kind of depends on the project. If you want to know the truth on PDH, we wanted to make sure we had every bit of that contracted and turned into an annuity. If we see a lot of upside, we’ll probably take less of a contract needs because we see upside on the assets. So, it really depends on the asset. For example, on spot, I’m not going to tell you what it is. We know what we have to have contracted in order to build it.

Neal Dingmann: Makes a lot of sense. Thanks Jim. And then just one follow-up. Quarter-to-date, the marketing margins continue to look quite strong. And I’m just wondering with about a third of the — third quarter now in the books, and Waha prices remaining still quite volatile. I think we’re anything from $1.50 to negative $2. Just any update you would give on that marketing margins? Thank you.

Brent Secrest: Yes, this is Brent. So, from Enterprise’s perspective, our number is still the same. We have about $380 million a day of exposure. We’ve hedged a small amount for the balance of this year. But by and large, we still have a lot of exposure to all gas markets that originate from Waha.

Neal Dingmann: Perfect. Thanks Brent.

Brent Secrest: Yes, sir.

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

Manav Gupta: Hi, this is Manav from UBS. My first question is, can we talk a little bit about the CapEx creep that happened in 2024? What were the drivers of this? And could this repeat in 2025, do you have confidence that this will not happen in 2025?

Randy Fowler: I think we would come in and say we really didn’t see CapEx creep in 2024. We did modify the range. That’s why we gave you — gave the market an upper range. So, the lower part of the range change, but the upper part of the range is still $3.75 billion. And where we sit currently, we’re still — 2025, we still feel good about a range of 3.25% to 3.75%.

Manav Gupta: Okay. And in terms of PDH 2, you get it up in August, so should we assume it runs like that full rates by September? Or do you think it’s more of like you get to the full rate in the fourth quarter?

Jim Teague: I’m looking at Graham, and I’m expecting to run at full rates. We should be at full rates in September.

Manav Gupta: Okay. Thank you.

Operator: Thank you. As there are no further questions in queue, 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 your participation. You may now disconnect.