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. 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.

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.

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 inspected and 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 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.

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 on 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. 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 made 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.

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

Our first question comes from Theresa Chen of Barclays.

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?

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 rated. And like I said, we have additional brownfield opportunities ahead of us.

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?

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

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

Yes, this is Jim. I'll take that. Until now, we have been marketing a concept. Since receiving our construction license, we are now promoting a real project. We have conducted extensive research to assess our competitiveness against both single and multi-lightering. We tracked 563 ships involved in single lightering, and we ranked them into quartiles, finding that we performed better than 280 of those and competed effectively with the top two quartiles. In terms of multi-lightering, we analyzed over 400 million and outperformed those significantly across the board. Overall, we monitored 969 ships and excelled against 686 of them during that period. Now, we will see if there is market interest.

Thank you so much.

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

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.

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 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.

Tug is that LPG?

That’s LPG.

What percentage of LPG goes to China?

Around 43%.

Propane, butane?

Propane, butane.

Great. No, I appreciate that. And then I just wanted to revisit the capital allocation discussion around buybacks. I think we all understand at this point that enterprise is your 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.

Yes, Michael, this is Randy. Over the past few years, including 2024, we are aiming for buybacks in the range of $200 million. This approach is in line with our equity compensation practices. When we compare the equity we issue for compensation to the buybacks, we have seen a decrease in the total number of units outstanding over the last four years. This will continue to be our focus. For this year and the next, we are projecting growth capital expenditures between $3.5 billion and $3.75 billion. Next year, we estimate between $3.25 billion and $3.75 billion, which should help maintain those buybacks around $200 million. Looking ahead to 2026, we anticipate growth capex could be approximately $2.5 billion, which would provide us more flexibility to return capital. However, we need better insight into 2026 to determine how we will increase our capital returns through distributions and buybacks.

Great. Thanks Randy.

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

Hi, good morning. I wanted to ask about your thoughts on Enterprise's involvement in industry consolidation, especially since some of your midstream peers have been acquiring assets and doing bolt-on deals. Do you think this is the last major wave of consolidation in the midstream sector?

Okay, Jeremy, I'll take the first part of that. From a strategic standpoint, I will let Jim give his thoughts. However, what we are primarily focusing on is returns on capital and identifying what provides us with the best returns and growth in cash flow per unit because ultimately, that is what will drive value. We have examined several opportunities, leaning more towards asset acquisitions rather than mergers and acquisitions within public companies. So far, we've found that organic growth is presenting us with significant opportunities and better returns on capital while growing cash flow per unit. Additionally, the Navitas deal we completed also yielded strong returns and cash flow growth. This is where our focus lies.

Yes, strategically, we've always mentioned that any new ventures need to align with what we already have. We've discussed the plants we're constructing in the Permian, and I believe we are not done building plants yet. Therefore, the price has to be right, and it needs to match our identity. When we build a plant, we can choose its location based on what suits us. I prefer the organic approach, but we consider all opportunities that come our way, especially from investment bankers.

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?

This is Graham, I'll take that. Yes, power in Texas can be a challenge and it is constantly changing. We are taking steps with our projects to mitigate this by purchasing power generation and exploring other options. We collaborate closely with power providers to assess whether grid power will meet our needs or if we require backup power or alternative sources. Each situation is unique, and every provider differs, whether we are engaging in West Texas or East Texas. So, each situation is individual.

Got it, makes sense. I'll leave it there. Thank you.

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

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?

Yes, Tristan, this is Justin Kleiderer. I believe that updates on Bahia indicate we are still on track with our timeline. From a commercial standpoint, looking back a couple of quarters, the growth is supported by our gathering and processing platform, which Jim just mentioned, and we still see opportunities for building additional plants. Bahia will be positioned to handle those volumes. When considering NGL pipelines, it's important to consider the entire system that supports them. We have a top-tier system with extensive connectivity to most third-party plants that supply the system. Thus, assessing plant connectivity is essential to gauge potential capacity and utilization. Additionally, our pipelines offer us flexibility regarding possible repurposing options. In relation to Seminole, I believe it is a strong candidate for repurposing, and if that occurs, the NGLs would be directed to Bahia.

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?

We're adding an additional refrigeration unit there and expanding the existing dock infrastructure, making use of the current dock and pipeline systems, which will ultimately support 300,000 barrels a day.

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.

Great. Thank you guys very much. Appreciate it.

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

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 to be 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?

Yes, I remember Dan one time told me we were looking at something and he said, this might be the last deal, Jim. 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. I think we'll be surprised in the years to come, how good we'll do in that. 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.

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?

Sure, this is Tony. Jim mentioned in his prepared remarks that we don't see significant changes among producers. There is still a lot of incentive for producers to continue their activities due to the price of oil and their increasing profitability. Although they may not favor the current weak prices at Waha, this does not deter them from putting more barrels to market. Jim also noted that rich gas is consistently exceeding both our expectations and those of the producers. I would like to add that with Natalie's team, we engage extensively with commercial and technical teams, and during discussions with producers, we are looking into incremental rich gas beyond the type curves in our forecasts. There are several reasons for this, primarily due to some of the richer gas areas now being developed by producers, especially in the Delaware Basin, as well as the expected increases in gas-to-oil ratios driven by evolving multi-bench completion methods. As Natalie often reminds me, we aim for directionally accurate forecasts since no forecast is ever perfect. However, without sharing our observations from these commercial and technical meetings, our forecast would be lacking in direction. Jim, you mentioned an additional increment, and I would say that's beyond the roughly 30 billion of rich gas we projected for 2030. When you consider a basin generating that much cash, it may not sound significant, but given that it is liquid-rich, it quickly becomes a substantial number. That reflects the reality we are facing. Is there anything else to add? Natalie, do you agree?

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.

Got it. I'll leave it there. Thanks as always.

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

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?

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 efficiently 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?

Thank you. Regarding the second question, is there any potential for the company to take advantage of the wide isobutane to butane spreads we've observed, or is the main focus still on MTBE to butane?

We benefit from that spread.

From the isobutane to butane?

Yes.

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

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.

This is Tug, and I'll hand it over to Tony. In terms of enterprise exports to China, we're at about 43%, while the U.S. is around 52%, which is slightly below the U.S. average. I’d like to point out that our product does reach China, but it’s all through indirect channels, meaning we don’t have any direct contract exposure on the LPG front. However, we are observing a steady increase quarter-over-quarter. Now, Tony, over to you.

Yes. Regarding the demand for other liquids and Tug's mention of barrels going to China, we've been observing the significant growth of PDHs in China over the past three years, which has been remarkable. They currently hold a dominant position in the olefins market in Asia, particularly concerning PDH activities. This factor is crucial in the overall equation. If you are also referring to oil demand, from our perspective, there is nothing concerning about global oil demand. It's likely to grow between 1.2 million to 1.4 million barrels per day year-on-year. That figure is quite respectable, especially considering the demand from China and some weaker economies. Other forecasters are likely to agree that this is the trajectory we are on.

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. What we're seeing is that's a lot stickier demand and it doesn't go away.

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.

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?

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.

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

Yes, I think there are questions regarding the legitimacy of various projects and whether we will continue to enhance the export capabilities of this country. Clearly, those with existing contracts tied to current assets will benefit. However, when it comes to expanding their operations, particularly in Asia, there may be uncertainty about their ability to grow and rely on the U.S. Regarding tariffs, I want to emphasize that we genuinely believe that if U.S. products are to be exported, the price must be sufficient to offset those tariffs, considering geographical factors and the transportation costs involved. This likely reflects the overall dynamics affecting U.S. pricing.

That's very clear. I appreciate all the thoughts today. Thank you.

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

Good morning everyone. Thank you for your time. My first question is about the capital project slide, which I always find helpful. Something you mentioned earlier caught my attention. Is it accurate to say that you won't incur future capital expenditures until a significant portion is contracted? Alternatively, do you have a specific amount or percentage of volumes that need to be contracted before making a final investment decision or spending on capital expenditures?

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 need 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.

Thank you, Jim. I have a follow-up question. So far this quarter, the marketing margins have been quite strong. With about one-third of the third quarter already completed and considering the ongoing volatility in Waha prices, which range from $1.50 to negative $2, could you provide any updates on the marketing margins? Thank you.

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.

Perfect. Thanks Brent.

Yes, sir.

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

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?

We believe there won't be any increase in CapEx for 2024. We adjusted the range, which is why we provided the market with an upper limit. Although the lower part of the range has changed, the upper part remains at $3.75 billion. As for 2025, we are still confident in a range between $3.25 billion and $3.75 billion.

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?

I'm looking at Graham, and I'm expecting to run at full rates. We should be at full rates in September.

Okay. Thank you.

Thank you to our participants for joining us today. That concludes our remarks. Have a good day.

This concludes today's conference call. Thank you for your participation. You may now disconnect.