Earnings Transcript for EPD - Q1 Fiscal Year 2023

Operator: Good day, and thank you for standing by. Welcome to the Q1 2023 Enterprise Products Partners L.P. Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Randy Burkhalter, VP of Investor Relations. Please go ahead.

Randy Burkhalter: Thank you, Gigi, and welcome, everyone. Good morning, and welcome to the Enterprise Products Partners conference call to discuss first quarter 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 and 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. And so with that, I'll turn the call over to Jim.

Jim Teague : Thank you, Randy. Today, we announced Enterprise is off to another good start for the year. We reported adjusted EBITDA of $2.3 billion for the first quarter of '23. We generated $1.9 billion of distributable cash flow, providing 1.8x coverage. We retained $863 million of DCF for the first quarter. We reported 7 operating records and 1 financial record in the quarter, mostly related to our pipeline activities and export volumes across multiple commodities. We had record pipeline and fee-based natural gas processing volumes, record NGL and marine terminal volumes and near-record total marine terminal volumes. In March alone, our marine terminals loaded over 70 million barrels of NGLs, crude oil, refined products and petrochemicals for export. Our NGL and natural gas pipeline businesses as well as our natural gas marketing and octane enhancement activities also reported strong increases in gross operating margin compared to the first quarter of last year. We also saw strong margins in our refined products business, offset by lower volumes in our propylene business, where PDH 1 was down for 24 days during the first quarter for planned maintenance. We remain on schedule to put approximately $3.8 billion of major projects in service this year. In the second quarter, we will commission PDH 2 and the expansion of the Acadian gas pipeline system. In the second half of the year, we will complete our 19th NGL fractionator, 2 natural gas processing plants in the Permian and put the first phase of the Texas Western Products Pipeline in service. We are running essentially full across all our assets, with the exception of the Rockies. We have significant expansions in our ethane, ethylene, propylene and LPG systems. We are upgrading export capacity and adding geographic diversity to our ethane export assets, with positions at Morgan's Point and now Beaumont, and expanding our LPG and propylene capacity at our Houston Ship Channel facility. Our ethylene export facility has been full since Day 1, and we're expanding that by 50%. Ethane exports have moved from being only consumed by a handful of niche players and point-to-point movements with significant growth in demand by several petrochemicals in Asia, Europe and the Americas. We recently completed new ethane export contracts that add 240,000 barrels a day with multiple counterparties. On SPOT, we received our recorded decision this past November and expect to get other permits in our license in the second half of the year. We are way ahead of other applicants, and we know what it takes to get a recorded decision. Two buoys and a motor boat to hook up to a ship won't cut it. We will have a 24/7 manned platform, vapor combustion and 2 pipelines that provide the ability to load multiple grades of crude oil and also able to evacuate those lines during a hurricane. Time is on our side as we commercialize this project, as we don't think it's needed until 2027. While the second quarter can be our weakest seasonally, we remain constructive on global market fundamentals even though the forward curve doesn't reflect that. In addition to low global inventories, we also note that OPEC+ seems to be intent on managing global balances. On the demand side, expectations for most consultants range from 1.4 million to 2 million barrels a day for global demand growth in 2023. OPEC+ economists say they are standing by their forecast of 2.3 million barrels a day demand growth by the end of 2023. From our perspective, that sounds rich, although the last 5 weeks, U.S. crude inventories have drawn 20 million barrels. Countering these bullish fundamentals are concerns about the global economies, with central banks continuing to signal additional rate increases to tame inflation. Meanwhile, while the Chinese continue to ramp up travel in a huge way, their industrial manufacturing surprised to the downside when their PMI turned negative yesterday. Regardless of the near-term mixed signals which continue to signal a range-bound market near term, for us it's very hard to make a bearish call for oil in the medium to long term. And it's hard for us to be too constructive on natural gas. A wide gas-to-crude spread gives U.S. petrochemicals a structural feedstock advantage that, in our view, is permanent. A case in point is the current operating environment, where the U.S. ethylene industry is the only region that has been consistently profitable, while the rest of the world have been very selective in what they crack and how they operate. Single-use plastics are doing good, they're profitable, while durables have their challenges and their headwinds. Meanwhile, the U.S. refining industry is one of the most competitive and technologically capable in the world. In short, we expect U.S. production to continue to grow, and we expect demand at our docks will likewise continue to grow. If you want to know where we're going, look at what we're doing. We continue to expand our ability to export hydrocarbons out of the U.S. to points all over the world where it's needed. With that, I'll turn it over to Randy.

Randy Fowler : Thank you, Jim, and good morning, everyone. Starting with income statement items. Net income attributable to common unitholders for the first quarter of 2023 increased 7.3% to $1.4 billion, or $0.63 per common unit on a fully diluted basis. This compares to $1.3 billion, or $0.59 per common unit, for the first quarter of 2022. Adjusted cash flow from operations, or adjusted CFFO, which is cash flow from operating activities before changes in working capital, was $2 billion for both the first quarters of 2023 and 2022. We declared a distribution of $0.49 per common unit for the first quarter of 2023, which is 5.4% higher than the distribution declared for the first quarter of the prior year. This distribution will be paid May 12 to common unitholders of record as of close of business on April 28. As we mentioned on our February earnings call, we will evaluate another increase midyear. In March, we repurchased approximately 683,000 common units at an average price of $24.89 per unit, for a total cost of approximately $17 million. In addition, on a combined basis, our DRIP and employee unit purchase program purchased another 1.7 million common units on the open market during the quarter. For the 12 months ending March 31, 2023, Enterprise paid out approximately $4.2 billion of distributions to limited partners. In addition, we also repurchased $267 million of common units off the open market. As a result, our payout ratio of adjusted cash flow from operations was 55% for this period and our payout ratio of adjusted free cash flow was 75% for this 12-month period. Total capital investments in the first quarter of 2023 were $654 million, which included $570 million for organic growth capital projects and $84 million of sustaining capital expenditures. Our major growth projects that are sanctioned and under construction remains unchanged at $6.1 billion. We currently expect our 2023 growth capital expenditures will be in the range of $2.4 billion to $2.8 billion, which includes possible expenditures associated with projects under development and not yet sanctioned. Frankly, I have a hard time seeing us get to the upper end of this range. The changes to our CapEx ranges for 2023 and 2024 since our recent Analyst Day are projects under development, which are substantially comprised of potential expansions of our Permian gathering and processing systems and our NGL distribution system, including exports. None of this creep is associated with cost overruns or delays. We expect 2023 sustaining capital expenditures will be approximately $400 million. Our total debt principal outstanding was approximately $28.9 billion at the end of the quarter. Assuming the final maturity of our hybrids, the weighted-average life of our debt portfolio was approximately 20 years. Our weighted-average cost of debt is 4.6%. At March 31, approximately 97% of our debt was fixed-rate. Our consolidated liquidity was approximately $4 billion at the end of the first quarter, which includes $3.9 billion of availability under our credit facilities and $76 million of unrestricted cash on hand. In March 2023, we entered into a new $1.5 billion 364-day revolving credit agreement and a new $2.7 billion revolving multiyear agreement that matures in March 2028. These agreements replaced our prior credit facilities. For the 12 months ended March 31, 2023, our adjusted EBITDA increased 11.7% to $9.4 billion, compared to our trailing 12 months as of March 31, 2022. We ended the quarter with a consolidated leverage ratio of 3.0 on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and reduced by the partners' unrestricted cash on hand. Earlier this year, we announced a lower leverage target of 3.0x, plus or minus 1/4, or in a range from 2.75x to 3.25x. This change in financial policy, our lower leverage along with an established track record of growing stable fee-based cash flows and strong credit metrics resulted in Standard & Poor's upgrading our senior unsecured credit rating to A- with a stable outlook. We are appreciative of this recognition as the only A- rated midstream energy company. With that, Randy, we can open it up for questions.

Randy Burkhalter: Okay. Thank you, Randy. Gigi, we would like to remind our listeners that when they ask questions to limit their questions to one question and one follow-up, please. We can go ahead and start our Q&A.

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

Spiro Dounis : First question, on petchem, was particularly strong this quarter, at least relative to what we had expected. And I know in the past, you had all talked about maybe a 6- to 9-month period or a lag on inventories getting worked down globally before that really started to tighten. And so I'm just curious, Jim, I know you mentioned the weaker-than-expected PMI, but is something happening maybe sooner than you all had expected? Or are we still sort of waiting to see that destocking effect take place later in the year?

Jim Teague: I'm going to let Chris D'Anna answer you.

Chris D'Anna : Spiro, I think what really happened in this first quarter is that it was more of a supply shortage than stronger demand. I mean, we had decent demand. Just coming off of the fourth quarter, it was really weak. But ultimately, it was reduced supply from a couple of PDHs being off-line.

Spiro Dounis : Got it. Okay. That's helpful, Chris. Second question, just turning to Shin Oak. I know you all were sort of looking at potential alternatives there due to expanding that pipeline. Just curious if you can give us an update there on maybe what some of the potential alternatives could be and how you're thinking about the timing to make a decision there.

Jim Teague: I probably don't want to tell you what the alternatives are, but I will tell you we're trying to be capital-disciplined. And in the course of trying to do that, I guess we've kind of confused people. But we will loop Shin Oak. If we can find some options for that capital, then we'll probably do that. But make no mistake, our intent is we are going to look Shin Oak. And we've got a deadline -- and there's a deadline on the permit that we're going to have to be aware of.

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

Jean Ann Salisbury : NGL marketing has been falling in recent quarters and was quite low in this quarter. Can you talk through the drivers of this and if you see this as a trough?

Jim Teague: Lower commodity prices. But where is Doug?

Douglas Kiste: I think if you look at what we did last quarter in 2022, the first quarter of 2022, I think we had some very good opportunities in that quarter with our storage program that we didn't have in the market this quarter. Commodity prices probably have a little bit to do with it, but there was just probably some opportunities last year that we didn't see this year.

Jean Ann Salisbury : Okay. That makes sense. And then kind of a broader question. Once the Houston Ship Channel is expanded, does Enterprise forecast Houston crude prices trading at least at parity to Corpus or maybe even at premium?

Jim Teague: Who wants to take that? Tony go…

Anthony Chovanec : So there's a couple of things we're doing, Jean Ann.

Jim Teague: Talk about the -- Jean Ann mentions it in her write-up. Talk about the -- Jean Ann says that the pipelines at Corpus are full.

Anthony Chovanec : We're getting some incremental barrels kind of month-over-month, and I'd just say if you say Permian grows 40,000 to 50,000 barrels a month, that we're getting our fair share on the Houston Western pipelines. There is some premiums that happen at Corpus on the docks. I wouldn't say those premiums are that much higher, and I wouldn't say that they're day-in and day-out. I think what you're seeing us doing on our system, Jean Ann, is we've implemented a new quality program. And so if you look at the quality of crude oil that we're getting right now across our docks, it's the best quality that we've seen since we've been up in operation, and I think it compares with anything that Corpus can offer. So I think some of that is going to be equalized. Some of the freight advantages we'll have to overcome. But I think over time, if you look at where our program is going on crude oil, I think that we're going to eventually get there.

Jim Teague: And what was your objective in changing the -- why did we change quality mark?

Anthony Chovanec : I mean, we did it for a couple of reasons. But I mean, one thing is we listened to our customers. We listened to our customers both on the production side, we listened to them on the refinery side here in Houston, and then also our export customers. But if you started going through the program and what we identified, there's probably a couple of folks out there that were trying to do a little bit too much aggressive blending, and we've effectively eliminated them and done a lot more routine testing in terms of maintaining the quality that we can offer these customers downstream. And ultimately, that's going to achieve higher prices.

Operator: Our next question comes from the line of Brian Reynolds, from UBS.

Brian Reynolds : Maybe just to talk on the distribution outlook and expectations. We've seen Enterprise raise kind of in that 1% to 5% range over the -- since 2018. Looking forward, with leverage below 3x and free cash flow still hovering around $1 billion after dividends in the next few years, kind of curious if we could see that DPU growth rate go above 5%? Or perhaps a little more CapEx kind of temper that distribution growth expectation?

Randy Fowler: Brian, this is Randy. Thanks for the question. I think coming in and really looking at a range of 1% to 5% and going back to 2018, I would probably differ in my perspective of how I would look at it. Because from 2017 through, call it, 2020, 2021, we were really in a mode of transitioning from more of an external funding model to now more of an internal funding model. And so we were very measured on what we did in distribution growth to be able to grow into that internally funded model. Since that point in time, I would really say since over the last couple of years, 2 years, we have grown more in the range of, call it, 4% to 6%. And like I said, as I mentioned in the prepared remarks, we'll come in and discuss with the board here middle of this year as far as what we want to do for the rest of this year on distribution growth. And again, we've demonstrated good EBITDA growth. Jim mentioned $3.8 billion worth of projects going into service for the remainder of the year. That gives us good cash flow growth that will support distribution growth down the road. And I really hate to come in and get more granular than that because I don't want to usurp our board or front-run our board. But I think we'll look to continue to come in and provide distribution growth and buybacks, for that matter, as far as getting capital back to investors.

Brian Reynolds : Great. Appreciate it. We'll wait for that midyear update. And then as my follow-up question, I'll take the CapEx question. Projects under development have increased by $1 billion for '23 and '24. You talked about in your prepared remarks that you see limited ability to get to the high end of that range. So kind of curious if you can just talk about perhaps some of the projects in the hopper? And then within the existing CapEx backlog, was there any CapEx inflation or perhaps pull-forward of CapEx into '23 and '24 that we should be thinking about?

Randy Fowler: I'll take the first part of the question. There was not any cost of any overruns or delays on projects. In fact, Graham and his engineering team have done a great job of delivering projects on time and, more often than not, slightly under budget. And really, the change that we've had since Analyst Day are more projects that, I guess, we've got a good bit of confidence in and we included them in the range, but they're still subject to being completely underwritten through commercial contracts. And I'd rather not elaborate into much detail. We'll just come in and go back in. And again, what I said in the prepared remarks, and a lot of it is what we talked about at our Analyst Day, where we're seeing most of the opportunities for growth are gathering and processing in the Permian, broadly. It is also in our NGL distribution system, including export facilities. So just seeing a lot of demand on that front.

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

Michael Blum : I wanted to ask about the marine export, particularly the LPG and SA that came in really strong this quarter. Just want to get your color on the market, what demand looks like, and do you think these levels are sustainable from here.

Jim Teague: Tug, do you want to take that?

Tug Hanley : This is Tug. We did definitely see strong demand this last quarter, and we're going to expect to continue to see that demand. Really it comes down to productions continue to grow. It's still a supply push and the barrels still having the price to clear across the water.

Jim Teague: Michael, I was -- I've been surprised, pleasantly so, at how well we've done on our ethane exports. And I'm surprised that we're able to do 240,000 barrels a day of new contracts, with more to come.

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

Tristan Richardson : Could you talk a little bit about PDH 2 and, overall in the petchem segment, how should we think maybe about that fee-based mix pro forma once that asset comes online relative to the sort of 70-ish percent fee-based we typically see in that segment?

Jim Teague: I think this one is 100% fee-based, isn't it, Chris?

Chris D'Anna : That's correct.

Jim Teague: So it's 100% fee-based, with all creditworthy customers, and we always -- Graham is sitting to my left. They always come in. We can do more than whatever the nameplate is. So we'll probably have some extra pounds to play with.

Tristan Richardson : Great. And then maybe just on EHT export expansion, could you talk a little bit about the mix of products you're seeing? I mean, you talked a lot about refrigeration at Analyst Day, and I think you highlighted that that expansion could be 120,000 a day. Should we think of it as pretty fungible across products or primarily focused on LPG? And then could the scope change for that project, just given sort of the strength you're seeing across the dock indicated by the first quarter?

Brent Secrest : This is Brent. So I think in terms of where it stands right now, it's propane, butane and some propylene slated to come on the second half of '25. We continue to look, Tristan, at is there another project there, but it's all under evaluation. But right now, it's slated to come on the second half of '25.

Anthony Chovanec : And I just want to correct a number. You said 120,000 barrels a day. Our LPG export expansion is north of 170,000 barrels a day.

Jim Teague: And we're talking about the ship channel widening. You might explain that. Bob, can you explain what you get out of the ship channel widening for Tristan?

Anthony Chovanec : Yes, sir. So when Project 11 is complete on the widening, which we expect to be by the end of '24, first quarter of '25, it will add 4 to 5 hours of daylight. And most of the products we deal with are daylight-restricted. So that's easily an incremental 15% to 20% additional cargoes that can come in if needs be.

Jim Teague: Which means, Zach, you sell out your refrigeration then.

Zachary Strait : The contract.

Operator: Our next question comes from the line of Chase Mulvehill from Bank of America.

Chase Mulvehill : I guess a lot of ground has been covered, but could I ask on processing margins in the Permian and kind of relative to your fee floors? Obviously, Waha is seeing a lot of pressure. So are we kind of at those fee floors for Waha at this point? And then also just an update on kind of how you're thinking about, I think it's 400 Mcf a day of latent capacity on your Texas intrastate pipelines, just how you're thinking about that, still holding it open or contracting it up? And updates on kind of how you see Permian natural gas egress between the brownfield additions and the Matterhorn when it comes online?

Jim Teague: Natalie and Tug.

Natalie Gayden : I'll answer the fee floor question. Post Navitas, for the first quarter of '23, we did hit more fee floors than, I guess, the end of '22. But less volume is being subject to the fee floor. So I'd call it 75% of the volume. And it's not very far under the fee floor. So long story short, I see probably upside for the rest of the year.

Tug Hanley : This is Tug. On the pipeline capacity question, we still have open pipeline capacity. We are utilizing it every day as marketing. But just like every decision here at Enterprise, if there's an opportunity to work with Natalie for a long-term contract opportunity, we'll evaluate that, we'll evaluate to continue to hold it open for SPOT opportunity.

Jim Teague: When we feel like it's the right time, we will contract that capacity.

Chase Mulvehill : Okay. Great. Makes sense. An unrelated follow-up on octane enhancement. You're still generating some nice gross operating margin there and really some nice non-fee gross operating margin as RBOB and butane spreads are still wide. So I'd be curious kind of your thoughts on how you see these spreads playing out the rest of '23 and how much you have hedged at this point.

Jim Teague: Do you want me to take it? Or do you want to? So we have -- right now, I think that octane enhancement is about 75% hedged. We feel pretty good about where those margins are going to be. There was an earlier question about LPG pricing. And I think as you see this production come on, you look at the ability for propane and butane to go find markets, I could see that being somewhat challenged, and that's to the benefit of our octane enhancement program. Are we going to see as good margins that we saw from the MTB uplift that we saw earlier this year? Probably not, but it's still a very good business for us.

Operator: Our next question comes from the line of Jeremy Tonet from JPMorgan Securities LLC.

Jeremy Tonet : Just wanted to kind of pick up a bit, I guess, on the Permian and natural gas. There's been some conversation out there with GOR ratios increasing. And just wondering if you could talk about what your experience or thoughts are there and how you see that, I guess, kind of impacting basin production, that's helpful.

Anthony Chovanec : Jeremy, this is Tony.

Jeremy Tonet : And takeaway dynamics.

Anthony Chovanec : Okay. Go ahead. All right. Yes, GORs, when we looked at the basin holistically, are absolutely going up. It's largely driven by the preponderance of drilling into more gassy areas, and think Delaware Basin compared to, say, the Midland Basin. So there's no question that the GORs are going up. And that's how midstreams are contracting, and that's what producers are doing. Producers look at their portfolio. They look at what they plan to drill. And gas GORs, the decline over time, oil declines faster than natural gas does. So that impacts the long-term outlook in this regard.

Jim Teague: Does that mean you'll have less crude?

Anthony Chovanec : Jim wanted to know, does that mean you have less crude? And I think there's a misconception, thanks for that, Jim, that we don't have the amount of crude that we had before because of GORs. And that absolutely is not the fact. And you can look at our forecasts, which we stand by. You have a lot of both. That's the bottom line. You have a lot of crude. There's been no change in those curves as we forecast. You have a lot of very rich gas. So the answer is it doesn't mean less crude. And ultimately, this is not a bad story. It's not a bad story for Enterprise. It's a great story.

Jeremy Tonet : Got it. That's very helpful there. And then just wanted to kind of come back to the LPG and petchem side, and you've touched on this a few different times across the call. But just wanted to see, I guess, what patterns you're seeing over the balance of the year. LPG exports, is that kind of onetime in nature and surprise? Do you see this strength continuing? People are concerned about a recession. How do you see LPG exports in petchem, I guess, kind of being impacted by these trends, looking forward?

Jim Teague: I think, and I'll hand it to Brent, LPG has got a price to export, period. And price creates demand. And it's going to have to price to export, and there will be demand for it. Brent?

Brent Secrest : I mean, the only thing I'd add, it's our fundamental belief that it will have to go fight to maintain some sort of margin. If there's some sort of issue, obviously, at Enterprise, we have a pretty good shock absorber, which is our storage footprint. And if we can play to sell, because there's another question about LPG exports. And why we're expanding our export capacity is because the market needs it. And if you look at infrastructure bottlenecks, our belief is that as the production comes online, it will price to export. But at some point, the export capacity isn't going to be there. And that's an opportunity for folks like Enterprise to participate in that market. And if you go out even further and you look at the overall demand, especially what's coming out of China with PDHs, there's going to be a period of time in there in '25, '26, '27 time frame where the U.S. producer has to catch up to the overall capacity and the overall demand. But all this is going to be healthy for the system.

Operator: Our next question comes from the line of Colton Bean from Tudor, Pickering, Holt & Co.

Colton Bean : Randy, coming back to Brian's question from a different angle, do you all view leverage as more of an output? Or are you intent on managing towards the target range? Meaning, are there any items you view as a balancing mechanism, whether that be distribution growth, buybacks, CapEx? Or would you let leverage drift below the range in any given year?

Randy Fowler: Colton, the range that we have out there I think is a sufficient range for us for the foreseeable future. It really comes in and gives us a lot of flexibility to come in and fund organic growth. If we see a surge in organic growth projects, I think it gives us the flexibility to handle that, stay in the range. I think it gives us the flexibility to come in and if we see an acquisition opportunity that we want to use cash or incur debt for, I think it gives us plenty of flexibility to do that as well as come in and continue to provide distribution growth and buybacks. So I know I'm not probably answering the question the way you wanted it to, but that range of 2.75x to 3.25x gives us a lot of flexibility. And when we get all these new growth capital projects coming online, and again, we've got a lot under construction now, I think we'll see more of that EBITDA, certainly full year of that EBITDA, show up in 2024, 2025. And then I think at that point in time, we'll reassess.

Colton Bean : Okay. And so it sounds like for the near term, expecting to stay within that range. And the question was more angled towards it seems like you guys are more likely to break the bottom end than the top end. And so just if we'd see a ramp in distribution growth or buybacks if it looks like you all were drifting into, call it, mid-2s or even low 2s?

Randy Fowler: Colton, I'd just hate to get the cart ahead of the horse. Let us get there first, and let us see what the situation looks like when that prevails. And I think we're going to do the responsible thing once we get to that point.

Colton Bean : That's perfect. And then maybe shifting over to gathering. So I think there's a $25 million step-up in the Rocky Mountain region called out. From what we were seeing, it looked like regional pricing was actually down specifically in the San Juan's, which I think is where you have those gathering fees indexed. So I guess, can you explain kind of what the uplift was there quarter-on-quarter?

Randy Fowler: Really, I think, Colton, what we were seeing was really for a period of time, I think especially January, we really saw strong natural gas prices more driven by California, both up in the Rockies and in the San Juan. Tony, I don't know if you want to...

Anthony Chovanec : Completely agree. Phenomenal prices. Definitely an outlier. And that's because the utilities just want to prepare and say we have to have the gas.

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

Theresa Chen : I wanted to touch on the near-term demand outlook for U.S. LPG exports a bit more. Going back to your comments about the Chinese PDH unit, what are you seeing in terms of the pace and ramp of them? And do you think there could be an incremental bid for U.S. cargoes later on this year due to lower LPG exports from Saudi Arabia and Qatar?

Randy Fowler: I'm sorry, Theresa. What was the first part of that question?

Theresa Chen : Chinese PDH unit ramp.

Randy Fowler: I mean, so I think you're seeing quite a few PDHs come online this year. You'll see some next year and then obviously the year after. I don't know if the run rates are going to be sustainable in terms of what they're doing right now. I think they're doing probably around 70%. There'll be some opportunities for LPG exports. I think the overall propane consumption is only going to increase. I just don't know if there's run rates over there in China are going to be able to be maintained. If you look at our opportunities, we have the availability of some spots. Those will probably get filled up, but it's not a ton. It's probably 2 or 3 spots a month, Tug, that we have available, right?

Jim Teague: It still goes back to the gas-to-crude spread as to how much those PDHs run. And as we said in our script, we can't make a bearish case medium to long term on crude prices, and we're not constructive on natural gas. So inherent net gas-to-crude spread ought to be more LPG and ethylene plants and PDH plants in Asia.

Theresa Chen : And the second part of the question related to U.S. LPG cargoes potentially getting a bid due to OPEC production cuts.

Jim Teague: By definition, I think if they cut crude, they cut LPG, Tug.

Tug Hanley : They do. But just, Theresa, they're not huge LPG exporters anyway. And they've been really outspoken that, at least for now, incremental barrels, whether they're up or down, will affect internal consumption. So they're just another balancing item in a market where barrels are pricing to get consumed. It's just not -- we don't see it as a big factor.

Theresa Chen : Understood. And Brent, going back to your comments about infrastructure bottlenecks on the LPG export front down the line eventually, where do you think the export constraint will come about? Is it dock space? Is it refridge capacity? Is it tonnage? What does that look like?

Brent Secrest : I mean, I think it's refridge capacity. That's where it starts to begin with. And I don't -- if you look at what the industry is doing right now, we're running at pretty high rates. The dock piece is easily -- easier to solve. But on the front end, I would probably say it's going to be refridge capacity.

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

Keith Stanley : I wanted to start with a follow-up on CapEx. So you're at about $2.5 billion this year. I think the potential spend for next year, $2 billion to $2.5 billion. A couple of years ago, I think the company talked to $1.5 billion to $2 billion as somewhat of a run rate for CapEx. So should we think of '23 and '24 as elevated CapEx years? Or is the run rate now higher just as the company continues to grow?

Brent Secrest : Keith, the opportunities are there. Just good opportunities at the time. What '26 and '27 looks like, we'll let you know when we get closer to that point. But right now, we just see a lot of good opportunities both on the upstream side and the downstream side.

Jim Teague: We're bringing on $3.8 billion worth of major projects this year. If you take our PDH 2 plant, our fractionator, our Acadian expansion, those will all be full on Day 1.

Keith Stanley : Second question, just you rolled out the Project 9.3 last quarter. At a high level, any areas of the business that are going better than planned? Any lighter than planned? Just any high-level comments on progress towards that internal target?

Jim Teague: We probably -- we have probably, on petrochemicals, we're over plan. So other than -- I can't think of anything other than the Rockies and I guess our Eagle Ford crude pipeline as we're hustling that. So other than that, Zach, have you got anything going? I hadn't called on you. So I felt the need to call on you.

Zachary Strait : I think segment by segment we're pretty close to where we planned.

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

Neal Dingmann : My first is on shareholder return. I'm just wondering, given how strong your financial position continues to be, with over $4 billion of liquidity, I'm just wondering what factors go into the decision on the unit repurchase on a go-forward.

Randy Fowler: Neal, it really -- I guess, we had talked that the buyback program is still more of an opportunistic program right now. And I guess good news/bad news is, frankly, in the first quarter we didn't see a lot of good opportunities. When we -- in the month of March, I think around the Silicon Valley Bank failure, there was more volatility in the market and the units were under pressure. And we saw good value, and we came in and executed then. Just our window wasn't long enough. We would like to have bought more, but the units rallied pretty quickly on the heels of that.

Neal Dingmann : That's great. It's great to hear. And then my second question, on petrochem specifically, it looks like the propylene side was slightly down, just largely, I think, mostly just on the planned maintenance. So I'm just wondering, can you remind me of any major planned maintenance for the remainder of the year, specifically for that propylene production facilities?

Jim Teague: Graham, have you got any?

Graham Bacon : We've currently got a couple of splitters and down for a planned maintenance after that.

Jim Teague: We've got a couple of splitters down right now for planned maintenance. But after that, I think we're done for the year.

Randy Fowler: And those splitter turnarounds, they're not going to -- they're not material to any financials.

Jim Teague: I'm going to hold you to that.

Operator: Thank you. At this time, there are no further questions. I would now like to turn the conference back over to Randy Burkhalter for closing remarks.

Randy Burkhalter: Thank you, Gigi. That concludes our call today, everyone, and we'd like to thank our listeners for joining us today. And have a great rest of your day, and goodbye for now.

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