Thank you for standing by, welcome to Enterprise Products Partners LP's second quarter 2026 earnings conference call. Currently, all participants are in a listen-only mode. After the speakers' presentations, there will be a question-and-answer session. To ask a question during the session, you will need to press star one one on your telephone. To remove yourself from the queue, you may press star one one again. I would now like to hand the call over to Joe Theriac, Vice President of Finance and Investor Relations. Please go ahead. Thanks, Latif. Good morning, welcome to the Enterprise Products Partners conference call to discuss second quarter 2026 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise's general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I'll turn it over to Jim. Thank you, Joe. Good morning, everyone. Enterprise reported strong volumes, earnings, and cash flow for the second quarter. These results were driven by strong global demand for U.S. energy, which was particularly strong during April and May. Our export facilities, pipelines, storage assets, and fractionation complexes work together to provide our customers with reliable access to both domestic and international markets. Our teams responded exceptionally well to the elevated demand levels. In the second quarter, we generated a record $2.8 billion of EBITDA, a 17% increase over the second quarter of last year, and that provided one times coverage of our distributions. We handled record pipeline and marine terminal volumes during the quarter. Total pipeline volumes were up 8%, and our marine terminals were up an outstanding 33% compared to the second quarter of last year. We moved 14.7 million barrels a day of oil equivalent. I remember being ecstatic when that was 10 million barrels a day. Now we're knocking on the door of 15, and we moved 2.8 million barrels per day across our docks. I think it's important that we recognize our engineering and operation teams for their outstanding execution during the quarter. Their efforts enabled Enterprise to accelerate construction activities and begin commissioning the expansion of our Neches River NGL marine terminal ahead of schedule. The team demonstrated exceptional responsiveness and operational excellence while meeting strong customer demand and maintaining the highest standards of safety and reliability that define Enterprise. Natural gas processing inlet volumes increased to 8.1 billion cu ft a day. In the Permian, we saw a 14% increase over the second quarter of last year, bringing our total inlet volume in the basin to 4.3 billion cu ft a day, reflecting continued growth in producer activity across both basins.. To support this growth, we recently approved the construction of Plant 11, a new 300 million a day natural gas processing plant in the basin, and Plant 13, a new 300 million a day plant in the Delaware. Beyond providing additional processing activity for our upstream customers, these plants will supply incremental Y-grade volumes into our basin under our Bahia and Cheniere pipeline systems. Those systems are currently operating at 86% of capacity. Those volumes would then move through our NGL value chain, supporting additional throughput across our fractionation storage and export assets. We also have approved the construction of Frac 15, a new 150,000 barrel per day facility located in Mont Belvieu. We expect Delaware Plant 13 will be placed into service in the third quarter of 2028, Plant 11 in the Midland Basin in the first quarter of 2029, and Frac 15 in the first quarter of 2028. These are exactly the type of projects that create value throughout our system and generate attractive long-term returns. One of the themes that continue to shape energy markets today is the growing importance of reliability and flexibility. Global energy markets remain highly dynamic, and international demand patterns continue to be volatile. Rather than attempting to predict every market movement, we continue to focus on what we do best, optimizing our assets around changing conditions. Our network of assets provide connectivity from the wellhead to domestic and end markets. They are well-positioned to capture value across multiple points along our vast value chain. That flexibility continues to be one of Enterprise's greatest competitive advantages. Looking ahead, that next major project scheduled for completion is our LPG export terminal expansion on the Houston Ship Channel. That should be in service by the end of this year. We're excited about the opportunities this will create as global demand for U.S. hydrocarbons continues to grow. Our outlook remains very constructive. Demand for U.S. energy, natural gas liquids, petrochemical feedstock, export services continues to support utilization across our system. Combined with a strong balance sheet, substantial retained cash flow, and a disciplined capital program, we're well-positioned for growth. Finally, I think it's important to thank our employees for an outstanding quarter. Their commitment to safety, operational excellence, customer service, and execution continues to drive our success. With that, it's yours, Randy. Okay. Thank you, Jim. Good morning, everyone. Starting with cash flow, the partnership's adjusted cash flow from operations, which is our cash flow from operating activities before changes in working capital, increased 19% to a record $2.5 billion for the second quarter of 2026, compared to $2.1 billion for the same quarter last year. We increased our declared distribution to $0.56 per common unit for the second quarter of 2026, which is a 2.8% increase over the distribution declared for the same quarter in 2025. This distribution will be paid August 14th to common unit holders of record as of the close of business on July 31st. The partnership repurchased $159 million of its common units during the second quarter of 2026, and $275 million for the first six months of the year. Total repurchases for the last 12 months were $404 million, bringing the cumulative utilization of our $5 billion buyback program to 34%. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 1 million common units on the open market for $40 million during the quarter. For the 12 months ending June 30th, 2026, Enterprise paid out approximately $4.8 billion in distributions to limited partners. Combined with the $404 million of buybacks over the same period, Enterprise's total return was $5.2 billion, resulting in a payout ratio of adjusted cash flow from operations of 56%. Total capital investments were $1.2 billion in the second quarter of 2026, which included $1 billion of growth capital projects and $140 million of sustaining capital expenditures. We currently believe our expected range of growth capital expenditures for 2026 will net to $2.9 billion-$3.4 billion after applying approximately $600 million in proceeds from asset sales we already received. The increase in 2026 capital investment since the beginning of the year primarily reflects the initial spending on long lead items for the 11th natural gas processing plant in the Midland Basin, the 13th natural gas processing plant in the Delaware Basin, as well as NGL Frac 15 in Mont Belvieu, and capital for natural gas gathering, compression, and power generation facilities to support our growth in the Permian Basin. For 2027, we expect our growth capital expenditures to be in the $3 billion area. Sustaining capital expenditures for 2026 are expected to be approximately $600 million. On both the fourth quarter 2025 and first quarter 2026 earnings calls, we stated that discretionary cash flow for 2026 had the potential to be in the $1 billion area. Even though our estimate for growth capital expenditures for 2026 has increased by over $700 million as a result of investments sanctioned since the beginning of the year, we still believe discretionary free cash flow for 2026 has the potential to approach the $1 billion area. Our total debt principal outstanding was approximately $33.5 billion at the end of the quarter. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio is approximately 17 years. Our weighted average cost of debt was 4.7%, and approximately 97% of our debt was fixed rate. At the end of the quarter, our consolidated liquidity was approximately $4 billion, including availability under our credit facilities and unrestricted cash on hand. Recently, we closed on an incremental $1 billion short-term credit facility, which brings total liquidity to approximately $5 billion. We elected to add this incremental $1 billion of credit capacity due to the ongoing volatility in commodity prices and the impacts higher commodity prices may have on our need for working capital. At the end of the quarter, our consolidated leverage ratio decreased to our 3.0 target on a net basis after adjusting debt for the partial equity treatment of the hybrid debt. Also reduced by our partnership's unrestricted cash on hand. Our leverage target remains at three times ±0.25. Joe, before we turn it over to you, Jim, I guess we need to address the elephant in the room. You talking about my retirement? Yes, sir. Yeah, I've always said at Enterprise, retirement is 100 or death, whichever comes first. Well, I'm not 100 and I'm not dead. At 81, 50 years in this business, 22 at Dow, 28 at Enterprise, there comes a time when you have to turn it over to the next generation. We've got some unbelievable talent in this company. What I think I'm going to miss most is the interaction with the people, even with Tug. We just have some special people here. I've known Randy worked with him for 28 years. The last five as co-CEOs. I think we've been a hell of a team, and I'll miss working with him. It's been unbelievably rewarding to be with a company that when Randy and I were first here, had an enterprise value of $1.8 billion, and now is over $120 billion. It's been a hell of a ride. The last thing I'll miss is all the poking Randy does at me throughout the day. Hopefully Randy picks that mantle up too. Back to you, Joe. All right. Thank you, Jim. Latif, with that, we're ready to open up the call for questions. Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone. To remove yourself from the queue, you may press star one one again. Please limit yourself to one question and one follow-up, or two questions to allow everyone the opportunity to participate. Please stand by while we compile the Q&A roster. Our first question comes from the line of Jean Ann Salisbury of BofA. Your line is open, Jean. Hi, good morning. Congrats to you, Jim, on your retirement. I hope you get to drink some really nice whiskeys with your newfound time. Thank you for all the help over the years. Thank you, Jean Ann. My question is probably for Corey or Tug, LPG lifting rates have fallen as you've brought on Neches River. Did this surprise you? A lot is obviously going on in the market at the same time, I guess my question is LPG export capacity already overbuilt? As my follow-up, in a related vein, would you expect to see the 300 KBD expansion that's coming on later in the year be more fully utilized, since it's more take or pay? Thank you. Hey, Jean Ann. This is Tyler Kott. I will take that one. Yeah, you're correct. There's a fair amount of export capacity that's come online and will be coming online, including our project and some other projects in the market over the next 12-1 8 months. Obviously it'll take the market a little bit of time to absorb that capacity. We may see a period of time where we have less volatility in terminal fees and just overall lower rates than we've seen the last couple of years. From our standpoint, we've been very intentional about contracting our capacity, our EHT expansion and really all of our system-wide capacity around LPG export, as we've said, we're about 90% contracted, we have relatively limited exposure to that scenario. We feel good about where we're at given how things look the next couple of years. Jean Ann, this is Tug. I'll just add that at NRT, as additional ethane volumes come online and VLECs get delivered, that capacity will ramp up to ethane transitioning propane PDH. That makes sense. Thank you. Thank you. Our next question comes from the line of Spiro Dounis of Citi. Your line is open, Spiro. Thanks, operator. Good morning, team. Jim, want to extend my congrats as well on the upcoming retirement. First question, maybe just starting with a fundamental one. If we go back to your fundamentals update earlier this year, you suggested a meaningful amount of natural gas and NGLs were being curtailed behind the system just due to Waha prices. Curious, do you have a sense for how much of that curtailed volume has come back to the market? What's still left to come, and maybe what that means for your 2027 outlook? Spiro, this is Corey. When we look at our forecast, I would say that our forecast really hasn't changed all that much. Looking at producer cadence, not a lot has changed for the large publics. I'd say the privates have come online a little bit more given some of the price volatility that we've seen, that has brought some natural gas. The pipelines have come up a little bit faster than I think the market expected, so we've had some pretty strong Waha prices. As time goes on, I think we're going to end up filling those pipes with gas that comes online as we get some of that choke back gas that I had spoken about earlier in the year to show up, and then also some of these gas tier benches over time will start to fill pipeline capacity. Great. Thanks, Corey. Second one, maybe just going to CapEx specifically around 2027. Curious how much of that $3 billion is sanctioned versus potential. To the extent there's still more left to fill there, should we assume it's largely sort of natural downstream extensions, more Frac, maybe more export, or could it be something else? Maybe more broadly, should we think about that $3 billion as a new baseline for growth CapEx, or are you still anchoring to that $2 billion-$2.5 billion longer term? Spiro, this is Randy. I think in the near term, the $3 billion may be the new level. Some of it is just the pace of growth that we continue to see in the Permian and what we need there, in terms of when we think about natural gas gathering, also compression and power gen. It seems like especially in the Delaware, whatever you're going to build, you got to bring your own power with you. I think that increases levels as well. As far as when we look out into 2027, of that $3 billion, probably 80%+ is probably already spoken for, just with the projects that we've sanctioned and have announced. Great. I'll leave it there. Thanks, Randy. Thank you. Our next question comes from the line of John Mackay of Goldman Sachs. Your line is open, John. Hey, team. Thank you for the time, and congrats from us as well, Jim. I want to go back to Spiro's first comment on the Waha picture. More specifically, you've been talking about kind of 2 BCF a day potential flush production when these pipes come. Could you frame up for us, just from an operator perspective, what that actually looks like? Are these existing wells being choked back? Are these maybe wells that have been completed but not actually turned in line yet? Maybe more specifically, what these producers might be looking for from a Waha price or something else perspective to really bring those volumes on. Go, who do you want? Hey there, it's Natalie Gayden. When we were estimating the amount of gas shut in, it was a combination of what producers we knew were shut in. It's typically the higher GOR producers that are exposed to Waha. As that gas comes back online, and you asked the question, had it not been fracked, et cetera, a lot of it had just been choked back. I would say that as that volume comes back online, we see that as more positive long term than the short-term volatility that's created through spreads. Not all producers need a positive Waha gas price to bring that 2 BCF a day online. They need a healthy gas price, a healthy Waha gas price that are still exposed to Waha. We benefit? We benefit in processing margins when that's true. We benefit in spread value. We benefit with our equity gas production we have. It's all good. Yeah, absolutely. That makes a lot of sense. Maybe just taking some of those latter comments, certainly second quarter benefited from some of these spreads. Just curious, your outlook for the back half of the year or into 2027, your ability to kind of keep holding some of those, whether it's been through hedging it out or maybe the kind of market environment staying constructive. Maybe just walk us through the next couple of quarters on a couple of those fronts. Thanks. Yeah, this is Todd. I probably won't speak to the next couple of quarters, but what I can highlight is what we saw in the second quarter. During the months of April and May, we saw an acute global demand for U.S. energy. There was a significant demand pull across the barrel of crude, LPG, ethane, and olefins VLECs. We saw this in the form of additional volume and higher margin. For the quarter, it resulted in around $200 million associated with that global need for energy. If you break that $200 million down, it's called a third NGL, a third crude, and then a third petrochemicals and others. If you look at it today, those strong cash differentials have largely normalized. In the next couple of quarters, then when does the stride open? Yeah. Look, we've spoken to it in the past time and time again, if volatility is there, the team will execute on it, we've proven it time and time again. Thank you for the time. Thank you. Our next question comes from the line of Julien Dumoulin-Smith of Jefferies. Your line is open, Julien. Hi, good morning. This is Andrew on for Julien. Thank you for the time. Jim, congrats on your retirement. Just two quick question from my front. The first one being, we're seeing a sequentially stronger quarter in crude, I think both from a volumetric and a per-barrel margin standpoint. Can you maybe kind of unpack a bit more in terms of how much of that is driven by equity barrels that are benefiting from the current crude volatility versus how much of that is long-term contracts? Maybe an extension of that, with the extra barrels moving from Midland-to-ECHO 1 to Midland to ECHO 2, how have the recontracting conversation been on the spare capacity on Midland-to-ECHO 1? Thank you. Yeah, this is Todd. I'll try to give you a little color on it, but if you look at the crude numbers at a high level, we benefited from higher Midland to Houston's pipeline spreads, and we also benefited from higher margins we're able to charge across the dock due to that strong cash premiums. On the contracting side, Jay and his team have done an amazing job continuing to remain highly contracted on our Midland ecosystem, and continuing to get additional contracts. Yep. No, that's very clear. I guess the second question I have is just, we've talked about a better outlook at the Permian from a gas perspective. Has that kind of changed your expectation around potentially recontracting the volumes on ATEX around volumetrically as well as from a margin standpoint? Maybe can you help frame your latest perspective on the magnitude of exposure here? Thank you. Andrew, this is Justin Kleiderer. On ATEX, it is still a dynamic conversation with our shipper customers, really just evaluating on a high level what is the highest and best use of the pipe. Let's also not hide from the fact that the tariffs in place today often exceed the value of the product that it moves. There is going to be some degree of a rate reset. We are just working with our customers to figure out what is the best and highest use of the pipeline, what gives them the most flow assurance that they desire. We are engaged in those discussions. More to come as that unfolds. No, very clear. Thank you very much. Thank you. Our next question comes from the line of Keith Stanley of Wolfe Research. Please go ahead, Keith. Hi. Good morning. Randy, wanted to start by clarifying your free cash flow commentary for the year. You raised the CapEx by $600 million-$800 million. You said you still expect free cash flow to approach $1 billion, free cash flow is only slightly lower than last quarter. Is that just simply much higher EBITDA than you previously expected, or are there any other items like working capital or other items that are driving that? Yeah, Keith, we really don't include working capital in that when we think about discretionary free cash flow, because working capital is going to swing around with commodity prices and also what opportunities are there from a contango standpoint. It really comes in the two moving pieces are really EBITDA and growth CapEx. If you would, while we've seen, that again, over $700 million increase in growth CapEx just because of excellent project opportunities. At the same time, our cash flow is up that much, EBITDA is up that much to which basically almost offset all we've seen in growth CapEx. Great. Okay. That's a big number. Second question. You're building now five Permian plants at one time. I think your historical cadence was more like two at a time. Would you characterize the driver of that as a faster growth outlook for the basin? Are you having more commercial success in winning market share? What do you expect as a plant kind of run rate cadence from here? This is Natalie Gayden. I would expect trending closer to two is probably the right answer. Of course, as producers change their whether it be their cadence or maybe they hit higher GOR zones, that obviously changes our assumptions. Five in the next, let's just call it three years, because one starts up in 4Q 2026, puts us at around a 1.7 per year cadence. We haven't even talked about anything in 2029 yet. Okay. More of a heightened period right now and then back to two per year after that. Yeah, Keith, I think one thing to note, since 2022, we've probably been increasing our capacity by a CAGR of 15%. Then if really, if you look at from the end of 2025 to the end of 2028, we're going to be growing it by about 11%. Just like you saw this quarter, second quarter this year versus second quarter last year, our Permian inlet volumes were up 14%. Again, this just as Jim said earlier in his comments, just coming in and bringing more of that inlet, extracting each one of the plants, extracts 45,000 barrels a day of liquids that flows into Shin Oak and Bahia and right into our frack complex, and then into our downstream assets beyond the frack. Really good positive development. Thank you. Thank you. Our next question comes from the line of Theresa Chen of Barclays. Please go ahead, Theresa. Hi, I want to go back to the export topic, looking past the recent volatility on export arbs. Focusing more on the long-term greater strategic reliance on U.S. energy exports in general. Are you seeing much by the way of changes in customer behavior, contracting activity, or interest from individual customers that have not come across your commercials that put in before? Any color around that would be helpful. Hey, Theresa, Tyler Kott. Yes, I think we said last time we had strong interest before this conflict, and we still have very strong interest. To your point, there has been a bit of increased interest from countries that maybe were typically a little bit more dependent on the Middle East looking to ship some of their long-term supply sourcing to the U.S. That's a function of that exposure and just the fact that U.S. exports are growing and we're clearing to some new markets as well. Got it. With the multiple refined products infrastructure assets under development, maybe closer to FID than not across your competitors, how does this change your view of product flows on both refined products within your footprint, but also the heavier molecules within the NGL footprint between Gulf Coast, MidCon, and you're reaching the Rockies? Theresa, this is Justin. I'll take the product side of that question. I think in general that, if you look at our TE system, we move products from the Gulf Coast up into the MidCon and Chicago. The trend there has been, as the MidCon has gotten weaker, that volumes on that system have continued to get pushed further south. Anything that debottlenecks or clears the overhang in that MidCon and Chicago area with the projects currently under development, I think our system is going to benefit from. Directionally, we want to see prices support more product movements from the Gulf Coast to further inland markets. Thank you. Thank you. Our next question comes from the line of Gabe Daoud of Truist. Gabe, your line is open. Thanks, operator. Morning, everyone. Jim, congrats to you as well. Was hoping we could maybe just curious to get an update on the sour gas side of things. Looks like you're drilling your third AGI well currently, which should bring training capacity to 750 million a day. Are you seeing any incremental growth opportunities beyond that on the sour gas side? This is Natalie Gayden. I'd say demand has remained strong. I'd say the system was essentially full prior to bringing train 4 into service. We have train 5 under construction. As you know, we have third AGI well underway. We're currently evaluating train 6, mainly because producer activity and interest continue to build there. Given that, I would expect that volumes and margins continue to grow. Got it. Thanks, Natalie. Then I guess just as a follow-up, last quarter, you had quantified the EBITDA uplift in 2026 or the outperformance. Given the strength year-to-date, could we maybe just get an update on the thoughts around the EBITDA outperformance this year and how we should think about the trajectory into 2027? Thanks, everyone. Sure. Okay. We talked about this really on the first quarter call, and I think Jim introduced the word modest. We were really expecting modest EBITDA growth from 2025 into 2026. That expectation was really on an oversupplied energy market with benign pricing. Obviously, this conflict in the Middle East added a lot of volatility, and as Todd spoke, a lot of demand for U.S. energy. Really any comment about 2026 and 2027, we would need a crystal ball what happens with this conflict going forward. Really hard to come in and, I guess try to predict or speculate on what it might be. What I go back to, the comment that we made at the beginning of the year was modest EBITDA growth this year, and that was really just going to be volume growth going across our system. Into what we said going from, again, 2025 into 2027, we saw the potential for 10% area of growth in EBITDA. Again, that was largely as a result of more volumes coming on through the system, whether it was volumes coming into new assets or whether it was coming in, we had done an acquisition of Oxy Rock system that we really weren't seeing any volumes since the acquisition through the end of this year. We'll be picking up volumes at the beginning of 2027 on that also helps. Really, we weren't really coming in when we said modest in 2026 with a potential of 10% up in 2027. That was, again, not any margin or benefit from commodity prices. That was strictly volume. I think that's still where our thoughts are as far as that trajectory. Any volatility or incremental demand across the dock or any optimization opportunities that we have is really on top of that. Long-winded answer, that was a difficult question. Yeah. No, totally. Thanks, Randy. I understand it's difficult to predict at this point, appreciate the thoughts. Thanks a lot. Thank you. Our next question comes from the line of Jeremy Tonet of JP Morgan. Your line is open, Jeremy. Hi, good morning. Jim, wishing you the best in retirement. We have appreciated your perspectives over the years. Thank you, Jeremy. Just wanted to turn back to the Permian and Waha, if I could. Pricing there turning positive, I guess, staying positive for a bit here. Just wondering, how long you see this persisting, Waha in positive territory? It seems like there's a lot of gas that is ready to be connected. Just curious how you think that plays out. If I look out further, when do you see constraints in the basins emerging after the current round of pipeline additions? Does the industry need another pipe in 2029 or 2030, or how do you think about that? I'll start. This is Natalie Gayden. Maybe Tyler can chime in. I don't think we try to predict Waha price. We probably could see Waha tighten again before 2027 as some of that shut-in gas returns and some backloaded production comes online. Again, we'd rather see a healthy Waha that supports our producers' economics, volume growth, and some of that long-term infrastructure development for us, because sustained volumes growing across our integrated system is really more valuable than short-term outsize basis dislocations. Yeah, I think there's obviously a lot of gas in the Permian, and the pricing will reflect how the infrastructure comes to market and the timing, and probably will continue to be a little bit of volatility. Got it. I guess as far as future expansion, when do you see the need for that? I didn't catch that. The what expansion? Future egress needs out of the Permian post the current announcement of pipes. Would it be needed for 2029 or 2030? Yeah, I think that depends on your belief of your wet gas forecast. It's our belief that higher GORs are absolutely true. It really depends on the producer community and what zones they decide to drill and where they allocate the rigs to. Yes, I do think another pipe gets built that hasn't been announced. Just curious, PDH operations, it seems like it's running better this quarter. How it looks in the third quarter so far? This is Graham. Second quarter was a good run for us on the PDHs. PDH 2 ran at design conditions throughout the quarter, had a good run on PDH 1. One minor issue on PDH 1 in the second quarter. As far as the third quarter outlook, we did have an issue in July where PDH 2 was down. It is back up and running, and PDH 1 is running stable and expect that for the quarter. Got it. Thank you. I'll leave it there. Thank you. Our next question comes from the line of AJ O'Donnell of TPH. Please go ahead, AJ. Hey, good morning, everyone. Congrats on your retirement, Jim. Most of my questions have been asked already. I do have one. This might just be directed at Natalie. Looking at natural gas processing volumes of 8.1 BCF this quarter, they were up slightly, like 4% year-over-year, even as the Permian inlet grew 14%. Relative to Q1, they were down a little bit. I was just wondering if you could provide some additional context on maybe what's going on as far as processing volumes outside of the Permian, and how you expect those to look over the rest of the year. I would say if your question is volumes outside of the Permian, I would say relatively muted, if that's even a word. Processing capacity in the Permian is still slightly tight. There's a significant amount of processing capacity coming online in the basin. Not just with our projects, but with some of our competitors. As mentioned, there is quite a bit of shut-in gas due to Waha price that was spread across the basin. I think if some of that returns, you'll see some of ours and hopefully some of other people's come back online and through our plants. Eagle Ford, don't you think we're pretty just steady? I always call Eagle Ford Pretty Steady Eddie. There's ebbs and flows, of course, typically it is a very stable basin. Okay. Thanks for the detail, Natalie. Thank you. Our next question comes from the line of Manav Gupta of UBS. Please go ahead, Manav. Good morning. You are somewhat unique because you're one of the biggest exporters of ethane. Can you talk a little bit about what you're seeing out there in terms of VLECs availability, that ramp, and how that increases your ability to export even more ethane to the global markets, given the disruptions we are seeing on the naphtha side? This could be something, a major tailwind going ahead. If you could talk a little bit about it. Hi, Manav, this is Tyler Kott. Yeah, you're right. There's a pretty big uptick in VLECs coming to the market, a few more this year and quite a bit more next year. You should see our volumes correlate pretty strongly to those VLECs coming online as our customers get their vessels and begin lifting on the contracts that we've executed against our capacity. There's certainly more demand out there beyond our capacity, we're in conversations with a lot of different people in a lot of different parts of the world that are seeing what you're talking about with the attractiveness of U.S. ethane. Perfect. Given the demand growth from both sides of power as well as LNG, we're starting seeing people say, look, Haynesville would become more of a core basin besides the Permian and the Marcellus, you have a lot of leverage in that basin. Can you talk a little bit about your leverage to the Haynesville Basin, what you see in terms of growth, and if Haynesville does become a much more of a core basin, how does it benefit your company? I think I got your question. Are you really asking for what we see for the Haynesville? That's right. I think the Haynesville to us, as you know, is a dry gas basin. It really depends. It's very price dependent. One trick pony, and yes, we will see peaks when that basin steps in for the market on residue supply. We also know that Permian is a growing gas at the speed of light. I think you just see Haynesville be the swing basin it has always been. Yeah. Hey, this is Randy. One thing I would add is in our Louisiana intrastate system for the Haynesville extension, we're just continuing to see large demand for that pipe and that pipe's sold out. The same thing for, if you would, the lateral that goes down to Gillis to serve the LNG markets. That's running, call it between 800 and 1 billion cu ft a day, and that's sold out. Again, seeing good demand pull across that intrastate system, as Natalie said, Haynesville's going to be really price dependent. Yeah. Manav, one thing I'll add, this is Corey. We have seen production growth for natural gas in the Haynesville slowly creep its way up over the year. We're getting pretty close to 16 BCF. If that trend continues, I think our forecast is pretty online. It's very constructive what the producers are doing in the Haynesville right now. Thank you, Corey. Thank you, Randy. Thank you. I would now like to turn the conference back to Joe Theriac for closing remarks. Sir? Thanks, Latif. 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 participating. You may now disconnect.