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Good day and thank you for standing by. Welcome to the Enterprise Products Partners LP Second Quarter 2023 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 Randy Burkhalter, Vice President of Investor Relations. Please go ahead.

Thank you, Norma and good morning everyone and welcome to the Enterprise Products conference call today to discuss second 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. 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 those – 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 that made during the call today. And so, with that, I will turn it over to Jim.

Thank you, Randy. Today, we reported adjusted EBITDA of $2.2 billion for the second quarter of ‘23 compared to $2.4 billion for the second quarter of ‘22 and $2.3 billion for the first quarter of ‘23. We generated $1.7 billion of DCF, providing 1.6x coverage. Enterprise retained $639 million of DCF in the second quarter, and we’ve retained $1.5 billion year-to-date. We had resilient financial results despite the impact of lower prices for crude and natural gas, NGLs, and petrochemicals. Our profits were negatively impacted by weaker processing margins for the first part of the year. Our petrochemical service segment continued to perform in spite of the low price and lower margin environment. During the quarter, we established six operational records, including our natural gas pipeline volumes, NGL fractionation volumes and 11.9 million barrels of oil equivalent of total pipeline volumes. We are also extremely proud of the fact that with the increase in our distribution last quarter, we crossed the threshold of 25 consecutive years of distribution growth, literally unheard of in the midstream industry. This is truly exceptional milestone across all industries and, most importantly, a real tribute to the core principles laid out from our very beginnings that Randa continues to prioritize today. Moving to growth capital, we started the second quarter with $6.1 billion in major growth projects under construction. We have since completed construction on four major growth projects that will provide new sources of cash. We have an additional $4.1 billion under construction. Completed major projects during the second quarter and early July include a 400 million cubic foot a day expansion of the Haynesville Extension of the Acadian natural gas pipeline system, which has sold out; our Poseidon cryogenic natural gas processing plant, which was our sixth processing plant in the Midland Basin, which is sold out; our 19th NGL fractionator, which is sold out; and our PDH 2 plant in Chambers County, which is sold out and ramping up currently between 65% and 70% and climbing. The three main – remaining natural gas processing plants we have under construction in the Permian Basin will go into service in late ‘23 and early ‘24, one in Midland and one in Delaware, and the first phase of the Texas Western products pipeline will be put into service in December. When we complete the next three Permian plants, we’ll have 16 processing plants in the Permian, with a capability to process 3.8 Bcf a day of natural gas and extract more than 520,000 barrels a day of NGLs, all destined for additional value-added services in our Gulf Coast NGL systems. Meanwhile, downstream of the Permian, we have major expansions underway for ethane, ethylene, polymer-grade propane, propylene, and LPG, expanding and upgrading our export capacity at the Ship Channel at Morgan’s Point and at Beaumont. Our new export projects are designed with an emphasis on flexibility and reliability, centered around a highly integrated footprint, with multi-product capabilities even as the world works its way through a significant petrochemical downturn, U.S. NGLs and olefins continue to get a lot of attention from petrochemicals focused on feedstock diversity and advantaged prices. In addition to multiple long-term export contracts we recently signed, we are also in discussions with counterparties from several countries for substantial amounts of additional natural gas liquids and olefin exports. This level of customer interest is what supports further expansion of our export capabilities. A wide gas-to-crude spread gives the petrochemical industry a feedstock advantage that is proving both durable and permanent. As Randy heard me say a million times, I grew up in that business and I’ve lived through more than a few cycles. Only the strong prospered through times like these, and U.S. NGL feedstocks sourced from shale, oil, and gas are again proving their growing importance. The durability of U.S. shales is evident in ever-increasing U.S. exports of crude, natural gas, natural gas liquids, and in exports of petrochemicals in various forms. In July, Enterprise crude oil exports will exceed a record 30 million barrels. Oil and gas has faced commodity price headwinds, especially compared to the premiums of last year when crude averaged over $100 a barrel during the first 6 months of 2022. We see no reason that crude should have been trading at the low levels of the last few months. In early June, OPEC+ announced they were extending their reductions into 2024. On top of that, the Saudis announced that they would unilaterally cut an additional 1.1 million barrels a day of production in July and August, with the option to extend these cuts as needed. Meanwhile, waterborne data confirms that Russia’s exports are coming down. Inventories of crude and refined products, both in the U.S. and globally, remain very low, while OPEC+ continues to demonstrate they are committed to price stability. Even though industrial demand continues to lag, consumer demand is strong, especially in developed nations. Crude oil supply demand fundamentals continue to indicate that we’re in store for much tighter balances for the remainder of the year and in 2024. And with that, I’ll turn it over to Randy.

Okay. Thank you, Jim, and good morning, everyone. Starting with the income statement, net income attributable to common unitholders for the second quarter of 2023 was $1.3 billion or $0.57 per common unit on a fully diluted basis. This compares to $1.4 billion or $0.64 per common unit for the second quarter of last year. Adjusted cash flow from operations, or we call it adjusted CFFO, which is cash flow from operating activities before changes in working capital, was $1.9 billion for the second quarter of this year, compared to $2.1 billion for the second quarter of 2022. As Jim mentioned, 2023 marks our 25th consecutive year of distribution growth. We declared a distribution of $0.50 per common unit for the second quarter of 2023, which is a 5% – 5.3% increase over the distribution declared for the second quarter of last year and a 2% increase over the distribution that we declared last quarter. This distribution will be paid August 14 to common holders of record as of close of business July 31. In the second quarter, we purchased 2.9 million common units for the quarter at a total cost of $75 million. For the first half of the year, unit purchases totaled approximately 3.6 million common units, for a total purchase price of approximately $92 million. Inclusive of these purchases, we have now utilized 41% of the authorized $2 billion buyback program. In addition, our distribution reinvestment plan and our employee unit purchase plan purchased an approximately 2 million common units on the open market, for a total purchase price of approximately $51 million, and that was also during the second quarter. For the 12 months ending June 30, 2023, Enterprise paid out approximately $4.2 billion in distributions to limited partners. These distributions, combined with $307 million in buybacks for this period, result in Enterprise having a payout ratio of adjusted cash flow from operations of 57% and a ratio of payout for adjusted free cash flow of 86%. Total capital investments in the second quarter of 2023 were $784 million, which included $683 million for growth capital projects and $101 million of sustaining capital expenditures. As Jim noted, we have $4.1 billion of major growth projects under construction, $1.1 billion of which are expected to begin service in the remainder of 2023. We continue to expect our growth capital expenditures for 2023 will be in the range of $2.4 billion to $2.8 billion, depending on any incremental system expansions and timing. We continue to expect sustaining capital expenditures for 2023 will be approximately $400 million. Turning to capitalization. Our total debt principal outstanding was approximately $28.9 billion as of June 30. Assuming the final maturity date for our hybrids, the weighted average life of our debt portfolio was 20 years. Our weighted average cost of debt is 4.6%. And at June 30, approximately 97% of our debt was fixed rate. Our consolidated liquidity at quarter-end was approximately $4 billion, and that includes both availability under our credit facilities and unrestricted cash. For the 12 months ended June 30, 2023, our adjusted EBITDA was $9.1 billion. This compares to $8.8 billion for the trailing 12 months ending June 30 of 2022. We ended the quarter with a consolidated leverage ratio of 3.0x 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. As a reminder, our leverage target remains 3x plus or minus 0.25. So, if you would, 2.75x to 3.25x. So, we are right in the middle of that range. And with that, Randy, I think we can open it up for questions.

Okay. Thank you, Randy. Norma, we’re ready to open it up to questions from our listeners. And I would like to remind our listeners to restrict your questions please to one question and one follow-up question and I’ll take it from – you can go ahead and take it from here, Norma.

Thank you. [Operator Instructions] Our first question comes from the line of Theresa Chen with Barclays. Your line is now open.

Hi. I’d love to get your sense on the third quarter outlook and beyond, just given the recent action we saw in NGL pricing and ethane, in particular. Would you be able to comment on this and will you expect pricing to do as the quarter progresses? And how does this fit with your ability to earn outsized margins along your integrated NGL value chain, as well as potentially cheap the $9.3 billion runway basis?

Yes. This is Jim. I think we feel pretty constructive on the second half of the year. If we look at our processing margins, Natalie, they are better than they – they’ve been moving up.

That’s right.

Okay. And in terms of outsized spreads, my experience is you can’t predict them, but they’re always there, and I think we might see more opportunity in the second half than we have seen in the first half.

Thank you. And then on the petchem front, can you just comment on what you’re seeing as far as demand goes and the ramp-up of PDH utilization and/or the underutilization on the ethylene production side?

Thank you.

Thank you. [Operator Instructions] Our next question comes from the line of Tristan Richardson with Scotiabank. Your line is now open.

Hey. Good morning, guys. Just curious, Jim, you mentioned discussions with new international customers that, maybe you haven’t had relationships with before in the past. Should we think of these incremental customers as largely around filling export expansions currently underway or would these potential relationships be for further expansion to your export capacity down the road?

We signed that contract, Tug, yesterday? Okay. You’re about ready to execute it? The one that we’re going to execute, I think, we’ve – we had one large one. I think it was 200,000 barrels a day that we executed recently. And we’re in discussions with at least two more, Tug? Four more. And our guys are headed to Asia for an extended trip, not too long. So, I guess it’s both, what we built and what we expect to sign.

Okay. Helpful. Thanks, Jim. And then maybe, Randy, just curious, as we’ve now seen PDH come online and Frac 12 commissioned, as well as a processing plant, I know it’s too early to talk about 2024 capital, but just thinking about the potential for this elevated spend for these large and critical projects kind of coming to a conclusion in ‘23 such that ‘24 could be lower than ‘23?

Yes. Tristan, on that, certainly getting PDH 2 completed, that was a big capital project. But when we come in and see the opportunities just in and around our system, I think, frankly, we’re going to be in that $2 billion, $2.5 billion range for the next 2 to 3 years. And some of that, I’ll have to say that $2 billion to $2.5 billion really is still excluding spot, which is still going through the licensing process. But hey, we’re just seeing a lot of good activity, a lot of good growth opportunities across the system.

Appreciate it. Thank you, guys, very much.

Thank you. [Operator Instructions] Our next question comes from the line of Spiro Dounis with Citi. Your line is now open.

Thanks, operator. Good morning, everybody. Actually, I want to go back to that a little bit if we could, just on capital allocation. So, I guess on my math, I think you still have you guys generating about 10% to 15% of operating cash flow that’s sort of unspoken for over the next few years, even with spot in there as well. So, just curious to get your latest thoughts on preferred ways to allocate that capital given your leverage levels are really already at sector lows.

Yes, Spiro. I think it comes back to, really, what you’ve seen out of us the last 2 or 3 years. It’s sort of all of the above. Certainly, in the last year, year and a half, we’ve picked back up on the cadence of our distribution growth. So, we’re – and again, that seems like the most direct way to return capital to our partners is through distribution bumps. But, I think we’ll continue to come in and sort of use all of the above.

Yes. Fair enough. Second question on Shin Oak. And, Jim, I’ll preface this question with I know you’re going to expand Shin Oak at some point, but I also know you’ve talked about short-term bridging solutions to get there. I was just curious if you guys have any updated thoughts on that.

I got a lot of thoughts on that, Spiro. I was in a 2-hour meeting yesterday with Brent and Justin. So, you can imagine what it’s like spending 2 hours with Brent and Justin looking at all of our options, all of our options. And our options could be we’ll add another line called – what are we calling that? Bahia. Or we could partially loop Shin Oak and take Seminole out of NGL service. The bottom line is we have to have more takeaway out of the Permian. And, I guess I’ve got to have another 2 or 3 hours with Justin and Brent. We’ll come up with a solution.

Sounds good. Appreciate the color, guys. Thanks again.

Thank you. [Operator Instructions] Our next question comes from the line of Jeremy Tonet with J.P. Morgan Securities. Your line is now open.

Hi. Good morning.

Good morning.

Just wanted to start off with some of the NGL dynamics as you’re talking about before. I think you mentioned how the ethane prices have been volatile as of late. And just wondering if you see that as kind of logistics constraints given heat in Texas or otherwise, and I guess future outlook for ethane and propane prices at this point given the volatility that we’ve seen recently?

Go ahead, Brent.

So, on ethane, I think what you saw last month is when nominations were due for ethane recoveries, the forward curve probably said not to recover. So, you saw a bunch of ethane get rejected in the Permian Basin. You couple that with some operational issues on various plants across the entire basin, there was probably some frac rates that were lower than normal, and that made ethane very, very tight. I think if you look out forward, I think some of that volatility is going to suppress, and I think we’d get back to probably more of a normal type ratio between ethane and natural gas. But there was a culmination of factors that caused that.

Hey. Graham, turn on your mic. We always talk – we worry about plants going down in the winter. What’s 103 – temperature down?

Certainly, there are some challenges with that, but I wouldn’t say it’s been a material impact on our operating rates. We’re generally designed for those conditions.

What about others?

I can’t speak for others.

Well, I’m trying to get you to.

And then just real quick on propane, when you look at just overall global demand, I think we’ve had four PDH plants come up in China so far this year. There’s 11 other PDH plants scheduled to come online for the balance of this year.

That’s propane. Is that all in?

I mean, if you say 100% capacity factor, that’s another 250,000 barrels a day. Those plants aren’t running at those higher rates, but call it 65% to 70%. It’ll certainly put another bid under propane just no matter how fast production comes online.

Got it.

I would hope that we’ve seen the bottom on propane. That’s my hope.

If not, it will still price to export, right?

That’s right.

Got it. That’s helpful. Thanks. And just as we look going forward here, we keep seeing Enterprise’s leverage dipping down below three. And just wondering if that trend continues, what should we expect at that point? Leverage just continues to decline or I think $2 billion to $2.5 billion of CapEx next year, could that increase, or just any other thoughts, in general, on capital allocation?

Yes, Jeremy. Again, we’re sort of in the middle of our range at 3.0x. And I think, again, the team is really bringing in some good commercial opportunities. We think growth CapEx would be $2 billion, $2.5 billion. And again, as I mentioned earlier, that is without spot. And so, I think we would just like to see it develop. As far as returning capital, we – I said we picked up the pace on distribution growth. Still doing some buybacks. Balance sheet is in great shape. And, Jeremy, I guess just staying in a position that – a lot of opportunities come along, and we just want to be in a good position to execute on them.

Got it. That’s helpful. Thank you.

Thank you. [Operator Instructions] Our next question comes from the line of Jean Ann Salisbury with Bernstein. Your line is now open.

Hi. Good morning. Has the scope changed a bit for the Beaumont export terminal? It looks like from the slides you’re adding propane exports there.

You’re pretty observant, Jean Ann. Go ahead, Tug.

Alright. So, yes, the scope has changed on that. We previously announced 120,000 barrels a day ethane train at Beaumont. And now, what we’re doing is we’re proceeding with that train, in addition to a 180,000 barrels a day ethane train that can also do up to 360,000 barrels a day of propane. So, we’re not adding any additional ethane-only capacity, rather what we like to call flex capacity. We’re doing that in lieu of our Ref 4 expansion, and we’re opting for a much smaller capital project at our Ship Channel facility to increase our butane loading rates and allow for fully refrigerated PGP.

So, Jean Ann, in our – in my script, I said multiproduct and flexibility, and that’s what – so Tug can go to somebody and say, look, you can take three tanks of ethane and a tank of ethylene or you can take three tanks of ethane and a tank of propane, so – or vice versa. So, we’re trying to get – fix it where those things will always be full, but not necessarily of the same product.

Butane, propylene, ethane, ethylene, you name it.

Interesting. Thank you. And then is the Acadian expansion running full already? And maybe more broadly, in your opinion, is Haynesville just completely full-on gas takeaway now until as new pipes come on?

Hey, Jean Ann. This is Natalie. Haynesville, for us, Acadian extension is full. Gas continues to produce in the – even on our gathering systems, we’re getting more and more gas every day.

Great. Thanks. That’s all for me.

Our next question comes from the line of Colton Bean with TPH and Company. Your line is now open.

Good morning. So, just shifting back to the backlog, on the expected ‘24 growth capital range, Randy, I think you outlined that $2 billion to $2.5 billion. Currently improved projects look to be closer to 1.4. So, can you just characterize the type of projects that you’re expecting to reach FID on and the hurdles you would need to clear to move those projects into the official backlog?

Yes, Colton. Brent, do you want to take some of this because you are on the front line of it?

Yes. I mean, just to generalize this, Colton, I think everything’s going to be centered around the Permian Basin. So, whether that’s an NGL pipe solution, whether that’s processing plants, or whether that’s an additional fractionator, it’s going to be all centered around Permian production growth.

Got it. So, effectively, all kind of NGL supply chain. Makes sense. And then on the operations side, it looks like Midland processing earnings were relatively flat Q on Q despite the lower NGL pricing. So, have we effectively reached fee floors for the acquired system at this point?

Yes.

Perfect. Thank you.

Thank you. [Operator Instructions] Our next question comes from the line of Keith Stanley with Wolfe Research. Your line is now open.

Hi. Good morning. Wanted to start on spot, just any update on commercial momentum and remaining permitting process, and how soon you could conceivably get to an FID on that project?

We – I think we should have our license to construct, Graham, in September, October?

Yes, that’s where it’s trending right now. Everything’s going well right now in the licensing stage, and we’re expecting in the next – within the next few months.

In terms of – I mean, we’re traveling the world on spot where we have a laser focus on getting customers on spot, and I think we will, and I believe we’ll end up building it.

Okay. And that could be by next year even to be starting construction on that, do you think?

Well, if Tug and Brent would get off their rear end and get to Asia and see everybody, we would probably – it would probably be sooner rather than later. But we are going to commercialize this thing. And we have got meetings. Brent and I are going to Europe later this month, Brent?

September.

In September. And the focus is on spot. We are pulling out all things to get it done.

Okay. Thanks for that. And the second question just on the year overall, so the project $9.3 billion target for EBITDA, you did $4.5 billion in the first half. But as you pointed out a lot, you have a lot of major projects starting up, commodities are improving. Just any updated thoughts on how you are feeling on that target, things that need to go right, areas where you may have cushion, etcetera.

I say this every time, that’s not guidance, but it’s a goal, and we reward all of our employees once if we hit that goal. And somebody asked on one earnings call, have we ever had a goal that we didn’t meet, we are bound and determined that our employees are going to be rewarded by meeting $9.3 billion goal. What’s going to help us, I think is if you talk to Tony. I mean crude prices, I don’t know what they are doing today, Tony, but they have been up $10 in the last, what…?

30 days.

30 days. The balances are tight. All of our plants are full. The key – and Graham knows this. I think the key is to keep the plants running because we will capitalize on any volatility.

Thank you.

Thank you. One moment for our next question, please. Our next question comes from the line of Brian Reynolds with UBS. Your line is now open.

Hi. Good morning everyone. Just talk on the crude business. It seems to be finding its footing in terms of margin opportunity for the first time since COVID. So, curious if you could just opine on whether you are seeing incremental barrels and opportunity come back to Houston as Corpus remains full and if we continue to see green shoots into the back half of ‘23. Thanks.

I think in my script, what I have said is we set a record for loading crude onto ships in the month of…

July.

July. Thank you, Tony. And yes, Brent, I think you are seeing barrels move only towards Houston.

Yes. I mean, I think…

And Brent before you answer that, but also talk about our quality improvements across the system.

I think fundamentally, we believe in Tony’s production numbers as we go forward. We do think that the Corpus pipelines are full. We think that we have done – what we have done on our system as it relates to quality has brought more interest. And I do think when we speak to our customers, they want a bigger and bigger position in Houston. So, I think over time – and the other piece on this is not all pipelines are created equal. There is other pipelines that go to Houston or go to Beaumont that are more challenged than our integrated crude pipelines. So, I think we are going to be the beneficiary of these volumes going forward.

HOU.

HOU helps.

And Brent.

Yes. I mean just the HOU being able to deliver and data Brent, and what we have done on our system, you are seeing the open interest on that contract continue to go up. We have sent records in the last couple of weeks on daily traded volume. I think ICE had a press release recently and went through some of those details. But all of this just put together lends itself to more interest in trying to get to Houston on our pipelines.

I am not supposed to ask questions, but I will anyway. Where is Jay? How many of your cargoes have met dated Brent specs?

Since we implemented the new quality specification mimicking the plot spec, we have met – every one of our export cargoes have met that specification since we adopted it in May.

Great. Thanks for all the color. And maybe to just touch a little bit on M&A, commentary coming out of the Analyst Day, it seemed like it was coming or attractive for Enterprise. But with nothing year-to-date and EPD continuing to maintain its high bar for returns, just kind of curious if you could just give us a forward-looking update on potential M&A appetite or whether other uses of capital could impact the use of M&A going forward? Thanks.

One of the things about building plants is you could build them where you want them, and that’s what I love about building all these plants in the Permian, and we are probably not through, and building the fractionator where you want it. So, that’s my color. But Randy is the one you should ask.

Yes. It makes me want to go back and reread our transcripts from the Analyst Day. I didn’t know we were that bullish on M&A. But yes, again, we will take a look at opportunities that come up. We are on every banker’s rolodex [ph]. So, we get an opportunity to take a look and – but I can’t say that we are predisposed to come in and jump on M&A if it makes sense, good return on capital, and if it fits the system, dovetails in, I think that’s one discipline that we have had over the years. It’s not building a collection of assets, but coming in and actually ties in and bolts onto our system and provides downstream or upstream opportunities. We will continue to look at that.

All make sense. I appreciate the color. Thanks.

One moment for our next question please. Our next question comes from the line of Michael Blum with Wells Fargo. Your line is now open.

Thank you. Hi. Good morning everyone. I wanted to go back to I think the opening comments you made. You touched on this a little bit, but I wanted to ask just specifically how you are seeing China demand right now as it relates to NGLs and where do you think that’s headed?

Yes. Michael, this is Brent. If you look at – and let’s take LPGs first that came from our terminal. At first quarter, that number was 24% of our volumes went to China. Second quarter, we averaged 38%. So, when you go back and talk about those PDH plants, I think that’s some effect right there. And then when you go to ethane, first quarter, it was about 33%. Second quarter, 26% went to China. What Tug has been doing on ethane contracts, I think you will see that number go up of what’s going to China.

Okay. Got it. And then just have like a broad question on drilling activity. Are there any regions you would highlight where you are just seeing a change in either reactivity or messaging from producers, either up or down?

Yes. This is Tony, Michael. We are in the middle of earnings season and producers are reporting. But if you look at, think Exxon, think Chevron, Diamondback reported today. Everybody is saying the same thing. They continue to see drilling and completion efficiencies and not by a little. They are seeing cost mitigation and predicting, depending on where they are in the value chain, some amount of even deflation on costs. So, better returns. When you look at – the longer laterals are key to what they are doing, cube development. I mean the producer continues to get even more and more efficient. So, we look at it all the time. We talk about it. We talk about it with each of our producers. It’s been difficult to look at the EIA numbers and try to figure out what production is doing, but I can tell you that we are on target for our own numbers to be in the 500,000 barrels a day to 700,000 barrels a day range increase year-end to year-end. And watch what the producers are saying on – during the second quarter. No one has a bad story. Everybody is very, very upbeat. And on top of that, I guess last but not least, our own calculation are ducts, so they continue to grow. So, not only are things going well for them, but they are building significant amount of headroom.

Haynesville?

Haynesville rigs, let’s look at completions there. Completions, frac crews in the Haynesville went from, call it, 15 to 18 down at a point to 7. They are back up to around 14 today. And if you look at the forward curve, the forward curve says Haynesville drillers should keep drilling, that they have value there. So, it is – the world is now watching it as that variable basin in the United States for natural gas production that could go, I am just going to use some generic numbers, it can go up 2 Bcf or it can go down 2 Bcf. And that’s a 4 Bcf swing over in about an 18-month period. That’s what you have seen through the cycles in Haynesville.

Perfect. Thank you.

Thank you. One moment for our next question please. Our next question comes from the line of Neal Dingmann with Truist Securities. Your line is now open.

Good morning all. Thanks for the time. My first question is on Permian processing margins. Given Waha pricing, I am just wondering how do you see the margins going forward, including the impact from your fee floors.

We think they will be better in the second half. They weren’t great in the first half. Is that fair?

It’s fair.

I think the trend, if you model out the forward curve, which is a good thing, on the percent, it hits the floor, it gets a lot less.

Okay. Thanks Brent. And then second just on the marine exports of the LPG and ethane. I think you all previously mentioned strong demand. And Jim, I think you even mentioned, I think it was around 240,000 barrels a day of new contracts. Is this still expectations? Are you seeing kind of production continue to grow in this area?

I think if you look at what we are doing, it kind of tells you what we believe. What we are doing is expanding our ability to export across the hydrocarbons chain. So, yes, we believe – if Tony is wrong, he will be somebody’s houseboy, I guess because that’s what we are doing.

Thank you, all.

Thank you. One moment for our next question. Our next question comes from the line of Neel Mitra with Bank of America. Your line is now open.

Hi. Thanks for taking my question. I wanted to ask your exposure to spot ethane prices. Were you able to sell spot ethane out of maybe some of your purity storage in Mont Belvieu to downstream players and benefit from that? And conversely, did you have any downstream obligations like, possibly being short on Morgan’s Point because of outages? Just wanted to see how that would kind of play out for 3Q now that we have a full month with prices over $0.30 a gallon.

One of the most valuable assets we have is our storage. And yes, we were able to take advantage of the volatility on ethane. And no, we have no issues of being short at Morgan’s Point or anywhere else.

Great. And then second question, we started the year off in the first quarter with very high LPG exports, and then now, we are seasonally weaker in the second quarter. When does that seasonality start to pick up so that it’s a benefit again for the second half of the year?

Brent, let’s let Tug take it, but I mean what’s our export volume?

Yes, we are going to be a little a bit soft in the month of August.

What do you call us up, 18 million barrels?

Yes, right around there.

I don’t call that soft.

But around September, we are fully booked up. And then I will just note as well that we are seeing duct margins increase specifically in the month of August and September forward.

Okay. Thank you.

Thank you. I am currently showing no further questions at this time. I would like to hand the conference back over to Mr. Randy Burkhalter for closing remarks.

Thank you, Norma. I think that covers it pretty well. I don’t have any closing remarks. I just like to thank everybody for joining us today and for our call and have a good day. Goodbye now.