Hello, and welcome to Enterprise Products Partners L.P. Q3 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask the question during this session, you will need to press star one one on your telephone. You would then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. I would now like to hand the conference over to Randy Burkhalter, VP of Investor Relations. Sir, you may begin. Thank you, Tawanda. Good morning, everyone, and welcome to the Enterprise Products conference call as we discuss our Q3 earnings. 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 with 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 in 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 it over to you, Jim. Okay, thank you, Randy. This morning, we reported solid results for the Q3, including Adjusted EBITDA of $2.3 billion. We had 1.7 times coverage of our distributable cash flow, and we retained $773 million. But we had challenges throughout the quarter. Record heat in August and September affected our processing plants' throughput and refrigeration at our NGL export facilities, and we experienced operational challenges at our PDH plants. We were also challenged by low natural gas and NGL prices. But despite these challenges, we handled record volumes across our midstream system, including our liquids pipelines, natural gas pipelines, NGL fractionators, and our marine terminals. In total, our pipelines transported 12.2 million barrels per day of crude oil equivalent. In terms of hydrocarbon exports, we reported 2.1 million barrels a day. While most people focus on crude exports, we focused on hydrocarbon exports. We exported everything from ethylene to crude oil. I think both Randy and I are very optimistic that our folks can do even more with the assets we have. Among some of the highlights so far this year is an unbelievable growing appetite for ethane exports. And of course, we're expanding our export facility, and this demand seems like it comes from all parts of the world. We're also continuing to see a growing appetite for LPG exports, and we're having productive negotiations in anticipation of getting our SPOT license to construct permit soon. Our fundamentals group forecasts have been consistently on the money in the past, and we have a lot of confidence in their future outlook. Therefore, this morning we announced an expansion of our NGL franchise. We're going to build 2 more 300 million cubic feet a day processing plants in the Permian, one in the Delaware and one in Midland. When completed, we'll have 19 processing trains in the Permian and 41 company-wide. Today, we also announced that we are converting our 210,000 barrel per day Seminole crude oil pipeline back to NGL service to support our needed Permian NGL takeaway. In addition, we announced our Bahia 30-inch NGL pipeline that will originate in the Permian and deliver up to 600,000 barrels a day of NGLs into our storage system in Chambers County. The beauty of this Seminole pipeline is we can seamlessly switch service between crude or NGLs, or as an expansion of our new TW refined product system. Finally, we announced today that we would build Frac 14 and a related DIB. The frac is similar to Frac 12 and will be able to fractionate approximately 200,000 barrels a day. This will bring Enterprise's company-wide fractionation capacity to 2 million barrels a day across 20 fractionators. We haven't just been announcing new projects. We've also been blocking and tackling, and I could take up this entire hour talking about what our people are doing every day to improve the performance of our existing assets. But one example of what we've been doing is a Permian initiative to improve the quality of the crude we deliver for our customers. We've spent money to develop a system to monitor crude receipts to ensure that those receipts meet our specs, which mirror the Platts Dated Brent specs. Since we've adopted this initiative in May, every WTI cargo we've loaded has met the Platts dated Brent specs. That is over 100 cargoes of crude. Our focus on quality is extremely important to the entire producer community in order to ensure that Gulf Coast crude remains highly desirable in global markets. We've also improved the quality of our Eagle Ford crude oil system. Not only has it made it easier to sell South Texas Sweet, it's improved the price that we get for that crude. Whether it's creating new growth projects or improving the performance of assets we have, our folks, Enterprise people, continue to deliver strong financial results, and we are exceedingly proud of each and every one of them. With that, I'll turn it over to Randy. Okay, thank you. Good morning, everyone. Starting with the income statement items, net income attributable to common unit holders for the Q3 of 2023 was $1.3 billion or $0.60 per common unit on a fully diluted basis, compared to $1.4 billion or $0.62 per common unit on a fully diluted basis for the Q3 of last year. Adjusted cash flow from operations, or which is cash flow from operating activities before changes in working capital, was $2 billion for the Q3 of both 2023 and 2022. We declared a distribution of $0.50 per common unit for the Q3 of 2023, which is a 5.3% increase over the distribution declared for the Q3 of 2022. The distribution will be paid November 14 to common unit holders of record as of close of business today. This year marks our 25th consecutive year of distribution growth. I guess you can say you can treat that distribution as a treat today. Our dividend reinvestment plan and Enterprise unit employee unit purchase plan purchased approximately 1.4 million common units on the open market for a total purchase price of approximately $37 million during the Q3 of 2023. Our utilization of the authorized $2 billion buyback program is unchanged at 41%, with unit purchases for the first nine months of the year totaling approximately 3.6 million common units, for a total purchase price of approximately $92 million. For the 12 months ending September 30th, Enterprise paid out approximately $4.3 billion in distributions to limited partners. These distributions, combined with $213 million in buybacks for the last 12 months, result in Enterprise having a payout ratio of adjusted cash flow from operations of 56% and a payout ratio of adjusted free cash flow of 90% for that 12-month period. Our buyback activity has been, admittedly lumpy over the last 18 months. EPD elected not to buy back equity in the Q3. During the Q3 buyback window, our VWAP, our volume weighted average price, was 98% of our 52-week unit price, and we elected to be patient. We fully expect to be back in the market doing buybacks in the Q4. We have established a track record of opportunistic buybacks over the last six years. We will continue to look for opportunistic windows to reduce unit count as we remain focused on improving our cash flow per unit metrics. We recently did a comparison of the six largest North American midstream energy companies, those with a market capitalization over $35 billion. Since 2019, EPD is one of only two companies to have actually reduced common unit/share count, and we are the only midstream company to reduce unit count over this time period without material asset sales. EPD reduced its common unit count by approximately 1% over this period, as did our peer. While this is a modest start, it is a consistent start of buybacks for six years in a row. We were also one of only three companies that grew distributable cash flow per unit by 15% or more. In fact, for this group of six midstream energy companies, EPD is the only company to have both reduced unit count and increased DCF per unit. We will include this peer comparison of DCF per unit growth, change in unit count, and change in debt in our upcoming investor slide deck after our peers file their Q3 10-Qs. We believe this will show EPD's balanced approach to increasing the value of the partnership for our limited partners over time. Total capital investments in the Q3 of this year were $826 million, which included $722 million for growth projects and $99 million of sustaining CapEx. Capital investments for the first nine months of 2023 were $2.3 billion, which includes $2 billion for organic growth capital projects and $284 million for sustaining capital expenditures. We expect our 2023 growth capital expenditures to total $3 billion. We expect 2023 sustaining capital expenditures will be approximately $400 million. As Jim mentioned earlier this morning, we also announced $3.1 billion of organic growth projects to expand our core NGL franchise in the most prolific basin in North America. These projects will provide additional natural gas processing and NGL pipeline and fractionation capacity to support continued production growth out of the Permian Basin. These growth projects will also bring additional volumes to our downstream NGL storage, pipeline, and marine terminal assets. In addition, facilitating Permian production growth also provides indirect business opportunities for our crude oil and natural gas businesses. With the addition of these four projects, we have $6.8 billion of major growth capital expenditures of projects under construction. We are currently forecasting 2024 growth capital expenditures in the range of $3-3.5 billion. We do not expect this level of capital investment to impact our distribution growth or our buyback activity in 2024. For 2024, we expect our buyback activity to be consistent with our history of approximately $200 million-$250 million a year. We are confident the returns generated by these organic capital investments in the heart of our NGL value chain will support the continued growth in EPD's cash flow per unit and free cash flow, which will support future returns of capital through both distribution growth and buybacks. Our total debt principal outstanding was approximately $29.2 billion as of September 30, 2023. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio was approximately 19 years. Our weighted average cost of debt is 4.6%. As of September 30th, approximately 96% of our debt was fixed rate. In 2024, only $850 million or approximately 3% of our $28.6 billion in term debt obligations, which excludes commercial paper, actually mature. For the three years, 2024 through 2026, only 13% of our term debt obligations mature. The combination of this modest maturity ladder, the average life of our debt portfolio, and high percentage of fixed-rate debt, provides the partnership with ample financial flexibility and provides a solid foundation to grow cash flow per unit. In other words, incremental cash generated from these new projects will not be materially eroded by having to refinance our existing debt portfolio in the current high interest rate environment, and thus, will better translate into cash flow per unit growth. I do not believe the value of our debt portfolio and liability management is fully appreciated. Our consolidated liquidity was approximately $3.8 billion at the end of the quarter, and this includes availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA was $9.2 billion for the trailing twelve months, ending September 30, 2023, compared to $9 billion for the trailing twelve months, ending September 30, 2022. We ended the quarter with a consolidated leverage ratio of 3.0 times on a net basis, after adjusting debt for the partial equity treatment of our hybrid debt and reduced by the partnership's unrestricted cash on hand. Our leverage target remains 3 times ±0.25, so the range of 2.75-3.25 times. With that, Randy, we can open it up for questions. Okay, thank you, Randy. Tawanda, we're ready now to take questions from our participants, and I would just remind our participants to please restrict your questions to one question and one follow-up. Okay? Thank you. Tawanda, go ahead. Thank you. Ladies and gentlemen, as a reminder to ask a question, please press star one one on your telephone and then wait to hear your name announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Theresa Chen with Barclays. Your line is open. Good morning. Thank you for taking my questions. Would you mind providing some more color about what drove the magnitude of the project FIDs at this specific juncture? What changed versus previous expectations, the annual growth CapEx cadence, and were some of these projects contemplated earlier in that $2 billion-2.5 billion CapEx range, but things got more expensive, or were there discrete projects that previously weren't in your runway, now been brought in? I guess what changed is the opportunities were there, Theresa. We felt like it was the right time to go. I know there's a lot of questions in the past on Chinook, and as we look at what we're doing out in the Permian, we felt like we needed to move on Chinook, given that we're going to build 2 more plants, bringing our plants out there to 19, which is quite a lot of Y-grade. Chris? Yeah, Theresa, this is Chris Nelly. You know, I think, you know, what we've been talking about on the last quarter's earnings call was that, you know, we were looking for what was the most effective way to expand our NGL takeaway capacity out of the basin. And, you know, as Jim alluded to, with some of the commercial successes we've had in expanding, and winning contracts on gas processing capacity, we came to the conclusion that we needed to build the full Bahia Pipeline. And as a result of that, you know, downstream of that, you need additional frac capacity. So in our minds, that these things go very much hand in hand, and it is in the core of our NGL franchise. You know, as evidence to that, Theresa, we took Seminole out of crude service because we need NGL takeaway right now until the Bahia Pipeline gets in service. So, Frac 14 will be full, and those two processing plants, when we bring them on, will be full. Right, Natalie? Got it. Would you also be able to provide an update on the commercialization progress for SPOT? And would it be possible to maybe move some or all of the ECHO export volumes over to SPOT, maybe supplementing that commercialization effort, if anything? And that would make space, I imagine, for incremental NGL exports, given that you do see a tremendous amount of NGL growth across your system underlying your project announcement today, which includes expansions nearly along every aspect of your NGL infrastructure value chain except exports. Yeah, we're gonna. We're We're having some productive negotiations with producers and large trading houses on SPOT. Frankly, I'm getting more optimistic by the day. We have that Record of Decision. We're still waiting on Bob Sanders, the license to construct, which we expect to have by the end of the year. We're continuing to work with MARAD and the Department of Transportation on moving that forward. So, timing is relatively short. Yes, sir. You got anything, Brent? No, that's—I think overall, the momentum on SPOT. It continues to get better and better. And your earlier question, this question, to me, it's what do we believe as a company? I think Tony Chovanec and his group need to take a victory lap for their ability to forecast production, and SPOT's gonna be about what the Permian Basin does from, from crude oil and all things, and that's what all these projects align toward. Thank you. To the question on more LPG out of the ship channel, I think everybody knows how much I love the Houston Ship Channel. And, you know, the neat thing about the ship channel is you have two-way traffic. From what I understand, daylight restrictions will be lifted November first, but then when they widen it, that's even, even we can get a lot more traffic up and down that channel, Bob. Yes, sir, that's absolutely correct. The wider channel is going to allow us to move more product, whether it's LPGs or crude oil. Or ethane. Got it. Thank you. Thank you. Please stand by for a question. Our next question comes from the line of Jeremy Tonet with JP Morgan Securities. Your line is open. Hi, good morning. Morning. Just wanted to come back to capital allocation. Appreciate the deep commentary and the prepared remarks there, but just wanted to kind of come in, you know, overlaying. Once these projects come to service, the projects announcing today, Enterprise appears well-positioned to generate significantly more free cash flow and drop leverage well below three times here, it seems. I believe your messaging highlights the ability to return more cash to investors with these projects. And maybe could you talk us through how you see Enterprise's capital allocation unfolding, and particularly given the potential for lumpiness, as you described? Yeah, Jeremy, you know, I think we've demonstrated as far as coming in and consistently. You know, and I'd like to say we've balanced the buybacks with continuing to invest in the partnership and grow cash flows per unit. And to me, the cash flow per unit growth is the main metric, that and leverage, to and keeping leverage in check are the is really the main metric, because the more cash flow per unit you grow, eventually this is gonna translate into free cash flow. Because, again, I think our growth CapEx is lumpy over time. You know, we in 2024, we said we were gonna be back in the range of 3-3.5 times. Some of that is, you know, we have a number of projects. I keep hating to use the word lumpy, but we have some material projects out there, whether it's our Neches River export, our ethane and propane export facility, or whether it's the Bahia Pipeline that are fairly large projects. Once you get past those, you know, the natural gas processing plants, NGL fractionators are very manageable growth CapEx. SPOT would be out there, you know, that if we cannot go ahead and finish commercializing that, but that's something that's gonna be spread out over 3.5 years. So I really see the period where we're investing to $3.5 billion a year is pretty limited. And so as a result, I think once you get out further, call it 2025, 2026, 2027, we ought to be throwing off a good bit of free cash flow, as you say. Right now, we don't see the need to come in and reduce leverage any more from where we are today with a target of 3.3 times. So again, that provides more cash for distribution growth and buybacks. ... Got it. That's very helpful there. Thanks. Then just wanted to pivot back to the projects announced today, a little bit more if I could. Clearly, the growing logistics needs associated with robust Permian production is the focal point for midstream here, highlighted by your announcement today. So diving in a little bit more here on the NGL pipe side, specifically, with today's announcement, and the NGL pipe additions appear to outpace, I guess, the 1.2 billion of NGL production growth Enterprise sees 2030. If you look at all the NGL pipes, I think, talked about in the industry, and granted, Enterprise has acreage dedications and a closed-loop system, which provides barriers to entry there. But do you see a risk to a looser NGL pipeline market down the road, and how did Enterprise, I guess, gain confidence in this size of an NGL pipe? You understand what you're talking about, the 30-inch Bahia? Yeah, just give it... Sorry. We felt like that was the right size, given what we see. You know, you know, what I have Tony looking at sometimes is, at damn Permian, is how about 10 stack pays? Yeah. Huh? Probably greater than that, particularly on the Delaware side, Jim. Yes. Plus, on the middle. I mean, and then I look at what somebody like Exxon CEO said about getting more efficient and getting better recoveries, and I think we're just scratching the surface, and I think we'll. You know, one thing Jim Teague hates and Randy Fowler hates are empty assets, and they won't stay empty for long. Yeah, and Jeremy, what I'd add also, and I thought the timing was good. Rusty Braziel had a note that also highlighted- End of last week. Yeah, end of last week. Tony, you want to hit some of the- Yeah, so look, when we look at our production forecast, the EIA actuals, for what those words are worth, are out, they're supposed to be out today or tomorrow. But if we go through what they have for actuals, just through July, they're showing 853,000 barrels of growth in crude oil production for this year so far. Now, their data is very hard to set your watch to, admittedly. But we had talked about 1.8 million barrels over a three-year period, 2023 through 2025, okay? And people said, "Well, and, you know, how do you gauge it year to year?" And I said, "Well, it's hard to tell, but just divide it evenly." I'll definitely take the over on 600 for 2023, without a doubt, for crude oil additions. I have to tell you, when I look at what's going on relative to activity and profitability for the producer, I have to ask myself, what's going to change this trajectory in 2024? Or for that matter, what's going to change it in 2025? You know, Brent, and thank you for the commentary. I mean, we spend a lot of time and a lot of effort. You know, we have sources that are significant relative to things we buy and then that we amalgamate with, I would call it, data science and data engineering. But last but not least, we have a significant amount of institutional knowledge from the army of people that we have. On top of that, you know, remember, we're taking Chaparral out of NGL service, and then we took Seminole out of NGL service. Now we're putting it back into NGL service, which says, "Hey, you guys need more takeaway right now," which is true. And then we will have the option once Bahia comes on, as to what we do with Seminole, and we can do one of three things with it, and we're pretty damn good at repurposing. I would, I would look at Enterprise's Permian assets as a portfolio, and I think we've demonstrated what Jim said, is that we, we use those pipes for how the market sees fit, and I would expect us to do that going forward. Got it. I'll leave it there. Thank you. That was more of an answer than you wanted, wasn't it? Thank you. Please stand by for our next question. Our next question comes from the line of Tristan Richardson with Scotiabank. Your line is open. Hi, good morning, all. Just in the context of the NGL production outlook you offered and really how critical and unique the export complex is, can you talk about the competitive landscape for NGL export capacity? I mean, particularly now, as some of your peers might like to enter this market, either via M&A or organically. Hi, Tristan, this is Jim. Yeah, we keep hearing that. You know, I personally think, and we made a mistake, and maybe it was I made a mistake when we were the only game in town, in that we went after pretty high fees, when I wish we'd have gone after lower fees, because we opened the door for our competition. That won't happen again. I don't know how a greenfield project competes with a brownfield project, especially when you have someone like Enterprise that's going to be damn aggressive in holding market share or even growing it. Super helpful. Appreciate the context. And then, you've talked about all of the folks at Enterprise are very focused and incentivized around Project 9.3. Can you give an update there as we near year-end? And, really, more importantly, any thoughts yet on incentive targets or goals for 2024? ... We, you know, 9.3 was never intended to be guidance, although every one of you guys took it as such. It was a goal. It was a goal, and I can't remember the last time we missed meeting a goal. Appreciate it. Thanks, Jim. Thank you. Please stand by for our next question. Our next question comes from the line of Jean Ann Salisbury, with Bernstein. Your line is open. Hi, good morning. There's not really any Gulf Coast LPG export capacity being added until, like, mid-2025. Do you see export capacity getting tight over the next year and a half, and could that be a tailwind for you next year? It'll be very tight, Jean Ann. All right. As a follow-up, you obviously announced a lot of organic Permian GMP growth today. Can you talk about how you looked at the pros and cons of organic versus inorganic GMP adds in the Permian? There's obviously a lot of options. With organic, you can build plants where you want them. And you don't have to deal with some acquiring a company that has a hell of a lot of dedications to other companies. So we just—we can build them where we want them, and when we control the liquids. Cool. That's all for me. Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Brian Reynolds, with UBS. Your line is open. Hi, good morning, everyone. Maybe a question for Tony to follow up on some of the Permian fundamentals. Clearly, a lot of these new project announcements are predicated on, you know, Permian crude and NGL forecast going forward. And Jim, you discussed some significant efficiencies that are expected in the Permian, you know, through this timeframe. So kind of curious if you can discuss, you know, how many of these efficiencies do we need to show up for these numbers to be realized in your view? And then second, kind of, what does this imply for, like, Permian rig count going forward, just seeing that we have seen some weakness going forward, but the medium-term outlook still seems to be intact. Thanks. Well, I'll start out. When we did our forecast, we projected what activity was gonna be. So Permian rig counts, we said, would range between 315 and 320, and they've ranged between 300 and 325, so not hard math there. For frac crews, we estimated between 135 and 150, and they're between 145 and 160. It's producer's behavior. And look, they're our customers. We talk to them. We plan projects and capital hand in hand with them. So we have a significant amount of what I'd call institutional knowledge. Tony, let me ask something. When your forecast, did y'all build in any growing efficiencies, or did you? No, that's a great question. We do not put a coefficient in there for growing efficiencies, and they've been growing for 10 years. I, I don't know what stops them at this point. But, now, to Jim, to your point, there are about 80 producers that have rigs working in the Permian Basin today. Out of those 80, only 20 of them have 5 or greater rigs running, okay? There is significant upside as far as that 60 producers that have less than 5 rigs running. There's a lot of metrics you can look at, but that's a simple one. That's the reality. I guess, Tony, also, the forecast that your team worked on did not assume a higher recovery of reserves? No, sir, it did not. It assumes historical recoveries, which are in the high single digits range. Now, we all know that at least two majors have said that that is not how they are forecasting going forward. Jean Ann, and all that would be using a Louisiana term, lagniappe. A little something extra. Oh, Brian. Great. Sorry. Thanks, appreciate the color on that. Maybe just a quick follow-up on the Permian natural gas liquids. You know, Seminole conversion, you know, seems to be catered towards the, you know, the highest margin molecule, whether that's crude and natural gas liquids, or I think you kind of referenced refined products in your prepared remarks going forward. So, you know, just given the opportunities for SPOT in 2025+, pet chem 2025+, you know, how should we think about maybe opportunities for Chinook and Seminole, kind of just go to the highest margin market? Is that kind of just a wait and see of what the market's gonna give you in that timeframe, or do you ultimately see Seminole, you know, returning back to crude service if you do wanna pursue, crude exports, in the back half of the decade? Thanks. I think we're gonna stay flexible, Brian, but, I mean, all of the above is possible. If those are full, it's possible, we'll just build another one. It's, it's really dependent on SPOT success, and like I said earlier, we're getting a lot more optimistic on being able to get this thing done with good commercialization. We're talking to a lot of people. Brent and I were in Europe what, three weeks ago, Brent? Yeah. Our sole purpose was to promote SPOT, and we got some pretty good feedback from people. Great, thanks. I'll leave it there. Enjoy the rest of your morning. Thank you. Please stand by for our next question. Our next question comes from the line of Spiro Dounis with Citi. Your line is open. Thanks, operator. Morning, everybody. A few cleanup questions from me. Randy, going to see if I can try and get you to say lumpy one more time, but just going back to, to SPOT and thinking about capital allocation next year, I think you mentioned that you'd still be able to sort of maintain this level of distribution growth, with the current CapEx program and, and not come off this sort of buyback plan. But I just want to verify, if SPOT does get sanctioned, CapEx presumably goes higher, and I think you guys lean on the balance sheet maybe for the first time in a while. So just curious, does all that still hold if SPOT does get sanctioned? Hey, Bob, once, once we get a license to construct, we're not through, are we? No, sir. That's just the first of about 24 that are needed. So, it's going to take a while to... license to construct didn't mean we can go out there and start digging ditches. No, sir. There's a ramp up on cash flow. Yeah. So, Spiro, I think again, with or without SPOT, it doesn't impact 2024, and frankly, most—I mean, if we're successful with SPOT, most of that's going to be 2025, 2026, 2027. And, I'm—we're in good shape to continue distribution growth and buybacks during that time period. Spiro, Chris, the one thing I would also add to that is I still think even if we get to a point where SPOT is sanctioned, we'll still be within our, you know, 3x leverage, ± a quarter of a turn. Got you. Okay. Helpful color there. Second, just going to M&A from two different perspectives. So one, I guess, on the upstream side, we've seen a lot of your customer base continue to consolidate. So I guess I'm curious to get your updated views on the potential impact to EPD into midstream more broadly. And then as we think about M&A for EPD, just given the slate of growth projects in front of you, I imagine you're sort of out of that market for the time being, but don't want to put words in your mouth. I like what Randy says: Price matters. The right deal, the right price, I'm not sure we'd back away from it, but it's got to be the right deal at the right price that fits us strategically. All right, I'll leave it there. Thanks, guys. Thank you. Please stand by for our next question. Our next question comes from the line of John Mackay with Goldman Sachs. Your line is open. Hey, good morning, everyone. Thanks for the time. I wanted to pick up on something that I think Chris mentioned earlier in the call. Just in terms of we're looking at all these new Permian growth projects on the NGL side, how much, how much of the flow do you think is going to come from, you know, your own plants on the EPD side versus third-party flows? And if we're thinking about that overall, you know, how do you think your market share trends on NGL pipeline throughput over the next couple of years? Justin, you got any idea? I think going back to some of the previous commentary, I mean, our GMP asset base is what the feeder to our NGL pipes will continue to be and will continue growing and on a percentage basis. Don't have the exact percent, but I bet it's 80%+ fed from our own GMP, and I would expect that's going to continue to grow as we continue to grow that footprint. All right. That's fair. I appreciate it. Maybe, maybe just shifting gears quickly, had the commentary on the PDH to ramp in there. Just can you give us an update now that we're a little bit into the Q4 and what we should look for there? Yeah, we did have some operational issues in the Q3 with the PDH. We're working some issues with the reactor, with the licensor. We should have that resolved later this month and expect it just to be a one-off and returning to full operation later in November. I appreciate the time. Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Michael Blum. Thanks. Good morning, everyone. Your company, the Wells Fargo. I'm sorry. No worries. Thanks. So a lot, a lot of questions, obviously, today on the projects and on supply, but I wonder if you can give us an update on what you're seeing on the demand side, particularly in China and India, and how any Panama Canal issues are impacting your exports. And then the second part of that question is really the same question, but longer term. You know, you're obviously very bullish on U.S. supply here for a long time. Where do you see all these, all these products being consumed? Do you see that shifting at all from the current setup? Thanks. Well, yeah, I'll, I'll start, and then I'll, I'll probably ask Brent a question. As I said in our script, Michael, it's been a pleasant surprise at the appetite for ethane. And that's not just—it's in Europe, that's in Asia, and we've got a couple more contracts that I expect that we will sign. So I, I thought ethane was going to be just a point-to-point project, and I, I, I wanted to build the first one, but I didn't really expect it. It looks to me like it's becoming, Brent, much more a traded product- More so, yeah. than I expected. And then, Brent, speak to... ... the type of people, the type of demand we see on thing, on LPG? Yeah, Michael, if you just look at in the Q3 where the LPG cargoes went, 55% went to Asia, 18% went to the Americas, 17% Europe, and 9% Africa. If you were to go trend that and look at the incremental molecule where it's going, Asia is far and away the leader of where each molecule goes. On the demand side of what that LPG is used for, about one-third is used for petchem use, two-thirds is used for, call it, human needs, cooking and heating. Tony gave us some numbers, I want to say it was yesterday. I'm going to try to look at these notes, but about IEA came out and said 1.5 billion people use LPGs for cooking and heating. If you look at the estimates through 2030, there's about 2 billion people who don't have access to it. If you look at the same consumption per capita, those billion people would need about 3 million barrels of LPG between now and 2030. And if you look at Tony's forecast, he's a little shy of 600,000 barrels of LPG from the US through 2030. So the Middle East will make up some of that, but at some point, the US producer is going to have to step up and fill that void. Hey, Chris, what was that organization that said propane and natural gas was a transitional? Yeah, Jim, MSCI recently came out and upgraded Enterprise to an A rating for their ESG score. And I think that really is a result of the, the stats that branches throughout. Again, if you think about what LPGs do in improving the quality of life for people in, call it, the Southern Hemisphere, that is an absolute game changer in needing 3 million barrels a day of an additional LPGs between now and the end of the decade, is really the reason why MSCI came out and said, "Okay, LPGs are now a green fuel," if you will. I'd like to add, relative to solar, and let's think about Africa, okay? It's going to happen. They're going to use it. But solar, no matter how you think about it, is not a good choice to cook and heat homes with. It simply is not. And people in Africa, they're going to get more. And natural gas and electricity are very expensive to move around. That's what we've seen over the last 10 or 12 years with LPG. Get a lot of energy, not hard to move around. It's not hard math. You just fill up a little tank- Yes, sir. Carry it home. Absolutely. Yeah. You know, and I go back to paraphrase Daniel Yergin, "This world has never done energy transition, it has only done energy addition." And I think we're going to see more of that. Great. Thank you for all the color. Appreciate it. Thank you. Please stand by for our next question. Our next question comes from the line of Keith Stanley with Wolfe Research. Your line is open. Hi, good morning. I had a question on the quarter and then a follow-up on the NGL pipe. So on the quarter, just NGL marketing's been softer this year than last year. Any drivers you'd highlight? And the frac margin, too, you had a huge step-up in volumes with the new frac, but the per unit margin was down a lot. Anything you'd call out there? You want to talk to fracs, Zach? Yeah, I'll start with the frac. So this quarter, we had two turnarounds on two of our fracs, so that increased our cost, obviously there. There is some uplift that we get from, from blend margins, which were down year-over-year, and then, ERCOT pricing, so just the hot summer, hit us this year relative to last year. And NGL marketing, Keith, I think most of it just has to do with structure in the market on a storage. So if you look back when COVID happened, we, we put on, obviously, a lot of contango. Some of that was extended, further long dated. And then we had some backwardation opportunities last year that, frankly, we just didn't see those opportunities this year. It's been less volatile in general this year. There just really hasn't been a lot of spreads. Got it. That's, that's helpful. And then, sorry, I have one on the NGL pipe. So just want to confirm it's a brand, it's a brand new pipe, so it's a greenfield new build. And if there's any way to give more color on what you see as the disadvantages of some of the other alternatives, like a cheaper looping of Chinook or even leveraging some of the third-party capacity that's getting added, just because it's a lot of capacity, I think that the market's seeing getting added all at one time. We looked at partial loops, and we didn't think that served what we needed. We decided to just build the entire pipe. I'll remind you, what was Chaparral's capacity? 130,000 barrels a day? 130. That 130,000 barrels a day, we've got to move on other, on other pipe. We're getting, I mean, Chovanec, you're around 600,000 barrels a day right now? 600. We need Seminole. Frankly, we don't leverage third-party pipes. We put it in our own. Thank you. ... Tawanda, Tawanda, this is Randy. We have time for one more question. Thank you. Please stand by for our next question. Our next question comes from the line of Neel Mitra with Bank of America. Your line is open. Hi, good morning. Thanks for taking my question. I had a question about the conversion and where you'll be offloading some of the accrued volumes. So from what I understand, Midland-to- ECHO 2 is moving some volumes, and the whole Midland-to- ECHO system is relatively full. So when you move this to NGL service, where do the crude barrels go? They go at Midland-to-ECHO 1, and we can get that up to about 600,000 barrels, 600,000 barrels a day. There's a marginal difference in cost, but more than made up for what we do with Seminole and NGL service. Okay, perfect. And then, not to beat a bad, dead horse, but the 700,000 barrels per day crude oil increase in 2023. Just wondering, you know, Tony, from your perspective, you know, for 2Q and 3Q, it seemed like we had flat hydrocarbon growth in general, out of the Permian, just with all the infrastructure constraints and the heat compression, et cetera. So are we-- are you expecting a big kind of September through December ramp? Because it seems like most of the growth that's come here to date has been the Q1, if I'm not mistaken. Yeah, I'll tell you, it's very hard to count production quarter- by- quarter. What people are looking at is the EIA numbers, which, by their own admission, have been very, very, very erratic, sporadic, both, both of the above. But through the Q2 and through the Q3, if you sat in our management meeting every Tuesday morning, you would hear about the amount of rich gas that wants to come to our plants and can't wait till our plants get built. So we really didn't see a massive lull. I understand that that's what the EIA reported, but the facts are, the other thing people worried about is the rig drop, you know, because the rigs kept dropping. But, you know, you have to remember that we had a tremendous build in rigs in 2022 to just make up for what happened during COVID. You couldn't stay like that at those levels forever. You had to replenish inventories, and you did. So it's very hard to look and say per quarter, but look, we're on a path to exceed 600, and I don't know what it takes us from that path, off of that path next year. End of story. Will one quarter have freeze-offs and one be hotter than the other? Yes, sir. But it doesn't matter. The calculus is so big because as Jim's pointing out, the basin is so large. There you have it. Right. Okay, thank you very much. Thank you. Ladies and gentlemen, at this time, I would like to turn the call back over to Randy for closing remarks. Thank you, Tawanda. We'd like to thank everybody for joining us today. That concludes our call. A replay of the call is available through our website via the webcast. And, again, have a good day, and I'll turn it back to you for any closing comments, Tawanda. Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.