Enterprise Products Partners L.P. (EPD) Q2 2022 Earnings Report, Transcript and Summary

Good day and thank you for standing by. Welcome to the Enterprise Products Partners Second Quarter 2022 Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. And now I would now like to hand the conference over to your speaker today, Randy Burkhalter, Vice President Investor Relations. Please go ahead.

Thank you, Victor. Good morning, everyone. And welcome to the Enterprise Products Partners conference call 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 this call today. During the 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, we can give no assurance that such expectations will prove ultimately 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 with that, I'll turn the call over to Jim.

Thank you, Randy. Today, we reported record adjusted EBITDA of $2.4 billion for the second quarter and that was driven primarily by higher margins and our octane enhancement business, higher natural gas processing margins and contributions from the Midland Basin assets we recently acquired. Those assets continue to significantly exceed our expectations. We generated a record $2 billion of DCF, excluding proceeds from assets sales providing 1.9 times coverage. We retained $974 million of DCF for the quarter taking us to $1.8 billion for the first six months. We achieved 11 financial records and four operating records and more details outlined in the press release and short, it was a good quarter. In this environment, we're not having any trouble keeping our systems full. Our Permian processing plants are running at capacity. We have two processing plants under construction, one in the Delaware, one in the Midland, and we've approved two more, one in each of those basins. When this build out is complete, we'll have 15 processing plants in the Permian, producing 530,000 barrels a day of liquids, which will take us to 36 processing plants as a company producing over 900,000 barrels a day. We also recently approved a project that expands our Shin Oak NGL pipeline by 275,000 barrels a day. And this is done through partial looping. We now have powerful options as it relates to take away for NGLs out of the Permian. We can close those loops to gain a lot of capacity or we can put Seminole back into NGL service, or we can do both. These projects do not change the CapEx guidance that we have communicated in the past. As we announced in Analyst Day, we're also expanding our systems in the Haynesville, over and above the Gillis Lateral we put into service last year. Our 2.5 BCF a day Haynesville system is unique. It not only reaches into the supply area, but it ties into interstate and LNG corridors but it also reaches into the lucrative Mississippi river industrial corridor, which is hungry for gas. We have significant operations and key basins that consistently represent 65% to 75% of the rigs running in the U.S. We've always focused not just on supply, but also markets. Today, we export 2 million barrels a day of crude oil, NGLs, refined products and petrochemicals. We started building this export position over 25 years ago and the leader of the negotiating team when we did that was the lady named Randa Duncan. That trend continues with the major export expansions we have underway for both ethane and ethylene. In addition, this last Friday, our spot project reached an important milestone with the FES – FEIS for the terminal put into the federal registry. I think it was in the Wall Street Journal, I read that the past three years we've gone from pandemic to pandemonium, when Russia invaded Ukraine in late February, no one was really surprised. Instead, the surprise to most is that the conflicts like it's going to last a while, the other surprise to most is the magnitude of the impact this war is having on both energy and agriculture. We're all coming to grips with the fact that many things we took for granted have changed. We have suddenly realized that what a just in time world we live in and how quickly prices shoot up when something breaks. We're also learning, some of us relearning about inflation, how strong and insidious it is. Most of our young people have never experienced inflation. Energy is reportedly responsible for over 50% of inflation as it is involved in every aspect of our lives. Add to that the high cost of food and increasing cost of housing. U.S. energy independence is now more valuable than ever. It is clear that Russia has a strangle hold on Europe. And Russia and China appeared to be aligned in policies that are in direct conflict with Western Values. Fortunately, the U.S. has an abundant energy resource. It is the fact that our crude oil, NGLs, LNG cargos are the only short cycle resources the world has left. We have tremendous hydrocarbons potential, but unfortunately it is squandered in the current political climate that is intent on restricting its development. Appalachia alone has over 25 Bcf a day of production upside, that's more than what Europe imports from Russia. However, this potential is unattainable, not by economics or resource, but by massive amounts of laws and regulations that are vague best and consistently applied and consistently. In addition to being the only short cycle resource the world has, our energy is environmentally superior. It's much cleaner because it comes from shale and it's produced here in the U.S. under environmental and safety standards that are second to none, it’s not oil and gas versus renewable debate as so many make it out to be. Enterprise’s view has always been, we are absolutely going to need it all. And what most call energy transition is actually going to be badly needed energy additions that will take place gradually. Oil and gas will be in high demand for decades. People who say otherwise are either extremely naive or have their own agenda. Demonizing fossil fuels, overt restrictions on investments and massive layers of regulation that are designed to keep it in the ground will only creep chaos in the form of ever increasing shortages and high prices. We need to learn from the mistakes of our friends in Europe and avoid risky dependence on unreliable or unfriendly suppliers for our oil and gas or for the materials and equipment needed for cleaner energy. Randy will go into this more, but the proposed mansion legislation is not everything the oil and gas community wanted, but the same will be said by the green movement. It appears to try to strike a balance between clean energy incentives and recognition that continued development of fossil fuels that's needed to ensure energy security and energy reliability. Randy?

All right. Thank you Jim. Good morning. Starting with second quarter income statement items, net income attributable to common unit holders for the second quarter of 2022 was a record $1.4 billion or $0.64 per unit on a fully diluted basis. This compares to $1.1 billion or $0.50 per common unit for the second quarter of last year. Turning to cash flows, adjusted cash flow from operations, which is cash flow from operations before changes in working capital, was $2.1 billion for the second quarter, this is a 23% increase compared to $1.7 billion generated for the second quarter of last year. Moving on to distributions and buybacks, we declared a distribution of $0.475 per common unit with respect to the second quarter of 2022. This is 5.6% higher than the distribution that we declared for the second quarter of last year. This distribution will be paid next week on August 12 to common unit holders of record as of the close of business on July 29. During the quarter, we also repurchased approximately 1.4 million common units at a cost of $35 million. For the 12 months into June 30, we returned over $4 billion of distributions to limited partners and $235 million of buybacks. So for the last 12 months, our payout ratio compared to adjusted cash flow from operations was 56%. And our payout ratio of adjusted free cash flow after excluding the acquisition, the $3.2 billion acquisition of Navitas Midstream was a payout ratio was 72%. Turning to capital investments. Total capital investments for the quarter were $383 million, which includes $301 million over organic growth projects and $82 million of sustaining capital expenditures. Capital investments for the first six months of the year were $3.9 billion, which includes $3.2 billion for the Navitas acquisition, $576 million invested in growth capital projects, and $157 million for sustaining capital. As Jim detailed earlier this morning, we announced three new projects in the Permian Basin, two new 300 million cubic feet a day natural gas processing plants, and a 275,000 barrel a day expansion of our NGL pipeline system. With these projects, we now expect 2022 growth capital investments to be approximately $1.6 billion and sustaining capital expenditures to be approximately $350 million. For 2023, we currently expect that our growth capital spending will be $2 billion. Our total debt principal outstanding at the end of the quarter was $29.1 billion. Assuming the final maturity date for the hybrids, the average life of our debt portfolio is approximately 21 years. Our weighted average cost of debt is 4.4%. And at June 30, approximately 97% of our debt was fixed rate. Our consolidated liquidity at the end of the quarter was $4.1 billion. And this includes availability under our credit facilities and $231 million of unrestricted cash on hand. Adjusted EBITDA was $8.8 billion for the 12 months ended June 30, 2022, which that yields a consolidated leverage ratio of 3.1 times after adjusting debt for the partial equity credit treatment of our hybrid debt, and also reduced by the partnerships unrestricted cash on hand. On August 1, we provided notice of our intention to redeem $350 million of the $700 million of junior subordinated notes D with a redemption date of August 31, 2022. These hybrid notes that were originally issued in August 2017 are redeemable on or after August 2016. These notes have a fixed rate coupon of 4.875% for the first five years, and then become floating at LIBOR plus call it 3% beginning August 2016. Based on current floating rates, the indicative spot floating rate for this note will now jump to 5.8% making these notes one of our highest cost debt issues, and really our only issue that is redeemable without a premium. Given the forecast that the Fed will increase floating rates by at least another 1% or more, we elected to redeem half of this issuance now using cash on hand and commercial paper to fund the redemption. Considering these notes receive 50% equity credit from the rating agencies in lieu of redeeming the entire $700 million of the notes, we decided to redeem half of the notes at this time. And in addition, we plan to opportunistically buy back up to 300 million of EPD common units over the remainder of the year. Our common units are a more expensive cost of equity versus the cost of the equity embedded in the hybrids. In regard to the proposed Inflation Reduction Act, overall, we have received positive feedback from our customers, especially with regard to the availability of federal leases for oil and gas drilling. Further in our efforts to commercialize a carbon sequestration system with Oxy, we believe the proposed changes to the 45Q credits could be a game changer for post combustion emitting customers. It was harder to come in or more of a challenge to come in and commercialize the carbon sequestration projects and attract these customers when the existing 45Q program was only paying $50 per metric ton and had no direct pay options. With that Randy, I think we can open it up for questions.

Okay. Thank you, Randy. Victor, we’re ready to take questions from our participants.

Sounds good. [Operator Instructions] Our first question comes from the line of Jeremy Tonet from JPMorgan. Your line is open.

Hi, good morning.

Good morning.

Just wanted to pick up maybe on that last bit there with regards to carbon capture and 45Q if the bill comes through as advertise lifting it to – lifting it higher there. Just curious, what type of timeline do you think things could happen, could things be developed? Would this happen in Louisiana before Texas, given Louisiana appears on the verge of gaining Classic well primacy by the end of the year, just trying to scope out what this opportunity set could look like for Enterprise over time?

Hi, Jeremy, this is Carrie Weaver. I don’t think it matters whether it’s Texas or Louisiana, our announcement with Oxy’s in Texas. And I think the relationship in working with the EPA can bring a project to fruition at the same timeline as in Louisiana if they gain primacy. And I think, we have received very positive feedback from customers as we’ve been discussing the project with them and the complementary collaboration with Oxy. So our goal is to be ready to deploy the project as soon as they’re ready. And we think this new legislation will be very encouraging to bring those decisions and those timelines sooner.

Got it. That’s helpful there. And then just wanted to touch base real quick on the quest for $9 billion of EBITDA. It seems like if you print quarters like this one that should be pretty easy to attain, but just wondering any updated thoughts there?

I don’t think it’s easy to attain, Jeremy. We’re just halfway through the year. And my role around here is to worry about everything. So I’m not – we’re not – I’m not high-fiving anybody at this point.

Thank you. Our next question comes from the line of Brian Reynolds from UBS. Your line is open.

Hi, good morning, everyone. Just to follow up on some of Jeremy’s comments on the CCUS project. EPD has a lot of opportunities in front of it in terms of large-scale projects, including CCUS, the potential for the cracker. And then in addition the spot export project, assuming regulatory certainty over the coming, back half of the year. Assuming we get the Inflation Reduction Act’s pass as it stands, curious the management could just talk about how it’s thinking about priority of projects and perhaps timing of pursuing some of these large-scale projects looking forward? Thanks.

First of all, we’re not looking at building a cracker. You put a press release out that you’re not looking at it. Next thing it’s on the front page of the Houston Chronicle business section. We have got in the FEIS per spot put in federal registry, but we still got another comment period to go. And I’m looking for Bob. We’ve still got another comment period to go, well, what are we 60-plus thousand comments to date? And another 90-day comment period or something like that.

It’s a 45-day comment period from last Friday. So it should be over by September 12. The last public meeting will be on August 23. And as you aware well in excess of 60,000 comments, Jim.

So once we get through this, we’re getting that knows how many we’ll have, then you got to slip through those. So I think we got it away – if we get this thing by the end of the year, I think we’d be lucky. It depends on the environment at the time we get it and what kind of customer base we can get as to where it fits in the priority list.

Great. Appreciate the color. And then maybe just to pivot to capital allocation. You’re looking to exit 2022 and 2023 well below the three, five target. Given the distribution rate this quarter and the small buyback, just curious if you could provide some incremental color on how we should be thinking about preferences for return of capital as we head into the back half of 2022 and into 2023, also given just higher inflation, et cetera? Thanks.

Yes, Brian, really our thoughts are still coming in and take all the above approach and that’s – I think that’s reflected by what we’re doing on these – calling these part of this hybrid note issue. I mean, it’s really – it’s not the highest coupon, but it’s near the highest coupon debt we have within the other side of it is we’re looking to come in and buy back up to $325 million, $350 million of equity between now and the end of the year, too. So a balanced approach between buybacks and debt reduction. I think the other thing, and again, I think this was represented what we did in 2021 is we came in and retained cash and really have been self-sufficient in funding our growth CapEx. But the other thing we had coming into the year is, we almost we had quite a bit of cash on hand and that enabled us to come in and fund a substantial amount of our acquisition of Navitas Midstream with cash and gave us the flexibility that the remainder that we could come in and just use commercial paper. So again, I think coming in and retaining cash for balance sheet flexibility paid off and how we came in and we’re able to capture opportunities that we didn’t come in and stress the balance sheet by coming in and doing an acquisition. So I don’t think you’ll see much change for us. You did see us come in also this time and bump the distribution 5.6% compared to last year. So again, I think you still come in and see us taking all the above approach.

Great. Appreciate the commentary and enjoy the rest of your day. Thanks.

Thank you. Our next question will come from the line – from Theresa Chen from Barclays. Your line is open.

Good morning. Jim, I wanted to go back to your comments earlier about the need for incremental NGL takeaway out of the Permian and your FID expansion of Chinook today. Can you just help us understand the puts and takes as to the relative economics of the Chinook expansion versus putting Seminole back into NGL service? And for the looping on Chinook, do you have the permitting in place for multiple wind right away? Or do you still have to get through some of that?

Well, Justin, you want to take it or Brent, which on these?

Yes. I’ll take it. Yes, so I think the Jim’s point, the expansion was – is clearly supported by the growth in the Permian that we’re seeing supported by our GMP expansions. And I think what really drove the decision in this direction was just preserving that optionality of what we do with some of those repurposing options that we have. There’s a lot of production growth that we expect coming out of the basin in the next three to five years. So that preserving that the value of a potential Seminole conversion for a later decision made, drove us to make this decision.

Yes, this is Tony. I’m going to add to something to that Theresa. Between now and 2027, we – can you hear me? Between now and 2027, we estimate that liquids out of the Permian Basin grow about 1 million barrels a day. If you look at what they’ve grown year-to-date, and you can’t find these numbers in anything, because EIA is reported in May and any other commercial reporters that do it, have only reported through April. But we think NGLs have grown already 125,000 barrels a day. I think natural gas is about 900, maybe even a little more. Those are big numbers, but I’ll have to tell you that. And you’ve heard it on these calls before. It’s what we’re seeing on our systems. You’re seeing it in the basis market in natural gas, and you’re seeing it on in our fracs and you’re seeing it in our plants, which is the reason for this announcement this morning in the customers backing all that. So getting to – putting some numbers behind what Justin said, that’s how we see it.

Thank you. And maybe as a follow-up to that, Tony, in light of the Ford basis for the Ford Waha [ph] basis, indicating that we may face a dire situation for residue gas takeaway to your point about incremental nat gas growth. So if we do face that situation in the first half of 2023, can you remind us how much incremental ethane recovery you think is realistic out of the basin? And in general, how do you expect the industry to work through this?

Let's talk about basis first, if you've watched the basis or whether you watch it on the ice or through brokers next summer has moved out to minus $2. It wasn't long ago that that was minus $1 or $1.20. So that tells you the pressure that the producer community is seeing from just incremental supplies. Relative to ethane somebody, how much ethane we think is being rejected in the Permian, I don't think it's…

It’s probably somewhere around 200,000 to 250,000 barrels a day, depends on the month.

Keep that wider basis once you extract that ethane, because it is a BTU. Yes, sure, absolutely. You can do everything you can to get your gas out because you're protecting your oil barrels.

But then that creates a situation for NGL pipelines. And so that's how that market will balance.

Theresa did that answer your question?

Yeah, thank you.

Thank you. Our next question come from line of Colton Bean from TPHC. Go ahead your line is open.

Good morning. So looks like total spend increased by about $900 million or so between 2022 and 2023. I guess, is that solely attributable to the new processing in Shin Oak capacity? And then if so, are you seeing any material price pressures or alternatively, are you having to build more gathering relative to what was required for the previous round of plants?

Colton, I'll take the first part of that and then I'll let Graham handle as far as what we're seeing, as far as any cost creep on existing projects. But now what we had said earlier was call it $1.5 billion or so of growth projects for 2023. And now we've seen that grow to about $2 billion and that's really just reflective of some of these project announcements that we had this morning.

In terms of on the project cost increases, we are seeing some increases, particularly the latter half of the year. I think we were pretty solid earlier in the year. We've seen cost increases anywhere from 10% to 15% depending on the type of material used in the project. We are starting to see some softening in some markets particularly steel seems to be turning around. Although labor markets are going to still be still be strong and have some upward pressure on cost as we go forward into 2023.

And Graham, as far as budget and status of our largest project PDH?

As far as PDH, PDH 2 we're still on track on, on time, on budget. All of our costs were effectively locked in at the time we did that project. So we don't really see any escalation on PDH 2.

Maybe Randy, just to clarify on the approved project specifically after 2023, going from something that maybe close to $1 billion, up to maybe closer to 2018, 2019 today, is that accurate?

We were estimating, I think we backed at our Investor Day back in March, we said that our expectation was that growth CapEx would be in the $1.5 billion to $2 billion area. And then again, some of that was going to move from, they were projects under development and now you're just coming in and seeing some of those projects being announced.

Understood then maybe shifting over to frac margins, I think Q4 and Q1 had a pretty significant increase. Looks like you all reported nearly $0.05 a gallon. And then in this quarter had a bit of a pullback closer to Q3 levels. So I guess just moving forward, do you characterize Q2 as more indicative of what you're looking at in the back half of the year? Or could we see a bit of a rebound there?

And Colton, are you really saying natural gas processing margins? Is that what you're referring to?

Specifically on the now your fractionation fleet, I think you guys reported $201 million or so for this quarter in fractionation specifically. And I think Q4 and Q1 had a pretty, pretty impressive margins there on a unit basis, so just looking at your unit margins for fractionation specifically not frac spread on the processing side?

Who is taking that?

Zach want to take it?

Yeah, this is Zach. I think on a go forward basis for the remainder of this year, I think it looks more like this last quarter, couple of things have happened. Power costs have gone up and also the blending at the fracs is also compressed. I think Q4 and Q1 were higher than normal.

Okay. And on the power side is most of that pass-through or you retaining some of that exposure on at the EPD level?

It's sort of a pass through we have a little bit of exposure to it and then just how much we have hedge relative to that exposure as well.

Got it. Appreciate that.

Thank you. Our next question will line of Chase Mulvehill from Bank of America Securities. Your line is open.

Hey I think this may have been me good morning, everybody. So I guess thinking about Navitas in the natural gas processing and NGL marketing business, obviously, you inherited a lot more commodity exposure when you acquired Navitas. So really, I guess maybe a couple of questions around this is, is this really kind of one. I don't know if you can kind of help us understand the commodity sensitivities within the natural gas processing in NGO marketing business. And then also talk a little bit about the Waha Basis, I think somebody mentioned it earlier but have you hedged that, do you have a lot of risk around that? I mean, so just kind of help us understand whatever risk you may or may not have if Waha Basis does blow out at some point next year?

Chase, this Jim one of the reasons we bought the Navitas is frankly, we wanted that commodity exposure given our fairly bullish sentiment. And what was the other part of the question?

I think the only place looking at Waha Basis exposure do we have..

I think we probably have 300 million a day of exposure and that's on purpose and I don't think we've hedged any of that, that I'm aware of as good.

Okay. All right. Unrelated follow-up. There's a lot of talk on the call today about retiring debt and obviously interest rates continue to move higher. So when we think about your target is 3.5% leverage ratio is there any chance that you think about lowering that at some point, if interest rates continue to kind of rise over the next year or two?

Chase I think we're – at this point we're still comfortable with the 3.5 times debt-to-EBIDA plus or minus a quarter, either side. So 3.25 to 3.75. I think one of the keys there is that again, at the end of the quarter, 97% of that debt was fixed and the average life was 21 years. So our exposure to floating debt and an increase interest costs are really, really low. We've been preparing for this environment for a dozen years.

Okay. Right. Perfect. I'll turn it back over. Thanks everybody.

Thank you. One moment for our next question. Our next question will comes from line of Jean Ann Salisbury from Bernstein. Your line is open.

Hi, good morning. I just have one. Year-to-date per Permian pipes to Corpus have been flowing at very high utilizations much higher than those going to Houston. Can you comment on the drivers of this? And if you expect this to kind of stay around until the Houston ship channel is expanded or maybe spot starts?

Hey Jean, this is Brent. I think there's been a lot more crude export in Corpus and I think that's starting to change, but it's a function of the pipeline capacity, that's one of that direction minus the local demand there, and everything else is going to head to the water. It's a function of the pipeline capacity, that's pointed that direction minus the local demand there, and everything else is going to head to the water. They can load larger ships than us. They can do it at higher rates. I think you've seen some flows change as win [indiscernible] has started up as more barrels are pointed toward Houston. They're taken from some pipes in Corpus, they're taken from others, but ultimately I think once spot goes forward that will change the flow patterns for crude oil exports.

Great, thanks. That's all for me.

Thank you. Hold on for our next question. Our next question will come from line of Neal Dingmann from Truist. Your line is open.

Good morning. This is [indiscernible] in for Neil Dingman. First question maybe it might be too simplistic, but why not just buy units back given to current, roughly 7.13% yield versus your filing this morning, suggesting the rejection of the notes that at roughly 6% yield?

Yeah, it's really just taking a balanced approach. I mean, we're coming in and the way we're thinking about it is, we're redeeming $350 million of debt, and we're redeeming $350 million of common units. And the coming in and redeeming $350 million of the hybrids is not a levering event, we’re buying the units back is a levering event, but again, it's just still all the above balanced approach.

Okay, great. Great. Thank you. That's it for me.

Thank you. One moment for our next question. Our next question comes from line of Michael Blum from Wells Fargo. Your line is open.

Thank you. Good morning, everyone. I just wanted to just put a finer point on the discussion around the distribution. So clearly, if you look at the last, I think at least two years, maybe longer, you've done one increase in the fourth quarter. Obviously, this is sort of a new or out of pattern. So just wanted to understand, is this a new pattern? Is this a one-time event? Is this a step change in growth rate? Just want to make sure I understand that better.

Yes. I mean, Michael, the board comes in and takes a look at the distribution rate every quarter. I want to say we went through a period, call it 2017 to 2021 where we were really – or 2020, really, where we were coming in and trying to make a shift in a financial model. And the old model was where you finance of substantial amount of your growth capital expenditures in the capital markets with a pretty good reliance on the equity capital markets. And the pivot that we began to make in 2017 was to come in and be more self-sufficient and coming in and funding our growth capital investments. And so that was – we were more deliberate on distribution growth and I think that's paid off. This year, I think one of the differences in this year – and then we've worked through the pandemic too, pandemic question mark, but the business has performed very well. We came in earlier this year and made in an attractive acquisition and that we talked about that being accretive. So that provided us an opportunity to come in and do a mid-year increase in the distribution and in light of what was going on from an inflation standpoint, we thought it made sense to do a midyear boost. I don't know if this is necessarily going to change what we do going forward, but we take a look at it every quarter, but we thought it was appropriate this quarter to go ahead and do a midyear bump.

Okay, great. That makes sense. Thanks for that. Also just one, had kind of a macro question. Jim, in your opening comments, you referenced inflation, higher interest rates, higher commodity prices. My question is, are you seeing any signs of weakness and demand across your business segments due to these factors? I know that's kind of like an open ended question, but I'm basically just kind of probing to see if we're seeing any signs of economic weakness in the…

Hang on Tony, I was with some customer last night who has a number of convenience stores and his read is, and they got more data on than you can say, grace over and his read good say he wasn't seeing that much, he seen some but not that much at the service station. Tony?

Yes. If you look at the data, it's yoyo to little bit in the – we were down a small amount, call it 5%, but when you listen to scope, call that was about a million barrels, but when you listen to the calls from somebody like Valero and PBF, they're definitive, that their wholesale demand is great, not just for diesel, but for gasoline too. So kind reflected in the frac spread, isn't it?

It is kind of reflected in the frac spread. You see some weakness in some of the elephant's markets, ethylene is overproduced now, and those plants are taken economic run cuts. You see PDH is going down in China, but I will tell you the flip side to that for Enterprise and Brent, tell me if I'm wrong, but if we don't export ethylene, we're going to export ethane, the demand for our ethane terminal's been phenomenal.

Yes. We're seeing record numbers, especially this month. And I think what we'll see going forward, if you looked across our ethane export we did a record number in July. If you look across our LPG dock, it's incredibly strong. We talked about crude exports. On the export docks, it's really picked up the last couple months, Michael.

Also, this is Jim. Tony spoke to overproducing ethylene that hurts the merchant player. The integrate is still making money, ethane into polyethylene.

Michael, the world is short, MMBtus in a good way for the world. And because of the natural gas situation, a good way for them to get more MMBtus is an ethane, propane and butane. So it's just the facts.

Great. Thanks for all that. Appreciate it.

Thank you. One moment for our next question. Our next question comes from the line of Keith Stanley from Wolfe Research. Your line is open.

Hi, good morning. I had two questions on the good results with the second quarter. First, on NGL marketing, it was up about $50 million Q2 versus Q1. It's a pretty high number. I usually think of NGL marketing is a little weaker seasonally in Q2. So anything in particular driving the strength in marketing there?

One of the things is a lot of what marketing does is fixed – all of the exports of, I think about LNG, those contracts are held by marketing, and I'm not sure about ethane. I think those are too, and I'm not sure about ethylene. Chris, is that held by marketing? Chris D’Anna: No, it's in PetChem.

If you look at some of the structural things that were going on the market between first quarter and second quarter, especially on the NGL side, that's why the second quarter was so strong.

Okay. And then similar question on processing. So obviously a very strong Q2 number there, headline frac spreads, which you'd usually look at for Enterprise were down in Q2. So not sure if there's a lag effect there or is it just Navitas is more POP and you're just seeing so much strength there that it's kind of overwhelming and bringing processing up.

Yes. Keith, I think part of it is we only had Navitas from February 22 or so in the first quarter. And then we got a full contribution from Navitas in the second quarter, but it does have a fee based floor ballpark, I want to say from a commodity exposure again, it's got a fee based floor, but we probably picked up an incremental 22,000 barrels a day of NGLs, another 3,000 or 4,000 barrels a day of condensate and probably 75 million, 80 million cubic feet a day of natural gas exposure. So that really provided some uplift.

Got it. Thank you.

Victor, we have time for one more question, please.

All right. Our last question, one moment. Our last question comes from the line of [indiscernible]. Your line is open. You might be on mute. All right, we'll go to the next person. Our next question come from the line of Michael Lapides from Goldman Sachs. Your line is open.

Hey guys, congrats on a good quarter. And thank you for taking my question, really a longer term one. When I think about the asset portfolio of EPD, you are the big dominant player in crude and NGL exports. One of the places where you're not really involved in is in the LNG business. Just curious, is that simply due to that fact that others moved much quicker than you guys did? Is that because you don't think it's an attractive business or is it a just evaluation and call? Just curious about how you think about longer term, your role in kind of the export of natural gas in the U.S. or from the U.S.?

I think our role would be focused on crude, petrochemicals and natural gas liquids. I think we – if anything, we miss the boat on LNG.

And on the quicker part, I don't know about the quicker part. I think that was an election that we made. And if we sort of go back in the history books, it was really LNG imports. And we were not a believer in LNG imports. And we just felt like the U.S. was going to have a good resource base. And U.S. LNG would be the first one to turn off as far as imports. And it was really the importers that really became the exporters when their import business model fell apart. And they had first mover advantage to come in and convert to LNG exporters and then, they were there because they already had sunk capital and they already had sunk equipment. So it was very easy for them to come in and do conversions. So really it was – are not being involved in the LNG imports, to a degree, put us at a disadvantage compared to those incumbent.

We are involved in delivering gas to export facilities, Gillis Lateral. And I think if I'm not mistaken, our expansion will be – have the capability.

Got it.

We love our position, exporting NGLs, crude oil and petrochemicals. And I said in my script, we're exporting just over 2 million barrels a day. That's not too bad.

Okay. Victor, we're ready to end the call. And so with that, the company will sign off and we'd like to thank everybody for joining us. And Victor, if you would give our participants replay information.

Awesome. Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect. Have a great day.