Enterprise Products Partners L.P. (EPD) Q1 2022 Earnings Report, Transcript and Summary

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

Thank you, Tanya. Good morning, everyone, and welcome to the Enterprise Products conference call to discuss our first quarter '22 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise's general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And so, with that, I'll turn it over to you, Jim.

Thank you, Randy. I’ve got two numbers to start off with: $2.3 billion in EBITDA, 1.8 times distribution coverage, I think that says it all. Looking back, it seems like the first quarter of each of the last three years has been a quarter of events. First quarter 2020 COVID-19 shut everything down and we had too much of everything everywhere and our people did pretty good. Last year in the first quarter of 2021, Winter Storm Uri wreaked havoc on the entire State of Texas, shutting in production like we've never seen, our folks did pretty good. And then in late February of this year, the world rather suddenly found itself dealing with the invasion of Ukraine by Russia, and dealing with having to supplement Russian energy to our allies in Europe, along with coming to grips with the growing importance of energy security. In all three scenarios, pandemic, massive weather events and a sudden global energy shortage, our people delivered. If for some reason you missed our analyst meeting, we announced seven new projects. And going into that analyst meeting, notwithstanding the invasion of Ukraine, we were bullish from both a supply and demand perspective for U.S. oil natural gas and NGOs, and we're planning for growth. During our meeting, we announced seven growth projects related to both supply and demand. We're going to build our sixth processing plant in the Midland Basin. That's the assets we bought from Navitas. In the Delaware, we're going to build our second plant at Mentone. In Louisiana, we're expanding our Acadian Haynesville natural gas pipeline by 400 million cubic foot a day. In Texas, we're reversing our Chaparral NGL Pipeline and a portion of our Mid-America Pipeline to move refined products from the Gulf Coast to West Texas, New Mexico, Colorado, and Utah. Just outside of Mont Belvieu but still in Chambers County, we're going to build our 12th NGL fractionation train. We announced that we're going to build an ethane export terminal at a site to be determined on the Louisiana, Texas, Gulf Coast. We announced that we were going to double our ethylene export capacity. And then shortly after the analyst meeting, we issued a press release with Oxy stating that Oxy and Enterprise were going to team up to build a carbon capture sequestration header system between Beaumont and Houston. But get combined these projects we have announced, will still fall within the $1.5 billion to $2 billion annual CapEx. Then I want to end the day with a few thoughts about the world's energy situation and how the U.S. is ideally positioned to step up with ample and reliable U.S. oil and gas. The U.S. has the capability to place Russia's exports of oil products and natural gas to our European allies, if we would unleash the God given shale resources that we're blessed with. After being dependent on the Middle East for nearly 50 years, the U.S. became energy secure and a net exporter of hydrocarbons over the last 10 years. While Europe moved the other way, depending on renewables and Russian natural gas. As Russia marched on Ukraine, their ideology came face to face with reality. Didn't have to be this way and it's not too late to correct it. If we would start being honest about the importance of fossil fuels, that importance being for decades to come. Unless we're ready to take a huge step back in human development, U.S. oil and gas production must continue to grow. Regulatory uncertainty, politics and green hyperbole have led to a gap in funding worldwide and we're finding out the hard way that planning and producing these resources isn't on autopilot. It takes skilled people, new infrastructure, time and money. Look no further than the cancellation of Keystone, suspension of federal leases, the numerous canceled projects to get gas out of Appalachia and plight of The Mountain Valley Pipeline to see the constant roadblocks caused by the attitude in Washington and in the courts. The U.S. is going to reach its full potential and provide global leadership in the face Russia's tyranny. Our politicians, regulators and the courts must start being honest about the world's need for energy and step up and support the needed infrastructure, including pipelines, plants and LNG export facilities. Otherwise, we'll find ourselves increasingly beholden to bad despotic regimes for energy and for minerals and metals required to add green energy solutions. Randy?

Thank you, Jim. Good morning. Starting with the income statement. Net income attributable to common unitholders for the first quarter of 2022 was $1.3 billion or $0.59 per unit compared to $1.3 billion or $0.61 per unit for the first quarter of last year. Net income was reduced by noncash asset impairment charges of $14 million or $0.01 per unit for the first quarter of this year. This compares to noncash asset impairment charges of $66 million or $0.03 per unit in the first quarter of 2021. Jim discussed distributable cash flow and coverage. So moving on to adjusted cash flow from operations, which is our -- what we call adjusted cash flow from operations, which excludes working capital changes. It was $2 billion for the first quarter of 2022, and this compares to $1.9 billion for the first quarter of last year. We declared a distribution of $0.465 per common unit with respect to the first quarter 2022. This represents a 3.3% increase compared to the distribution declared for the first quarter of last year. This distribution will be paid May 12 to our common unitholders of record as of the close of the business April 29. For the last 12 months, we returned $4 billion of cash distributions to limited partners and $200 million of buybacks. Our payout ratio of adjusted free cash flow, which again excludes the effect of working capital changes, and also if we exclude the $3.25 billion of the Navitas Midstream, was 80%. Total capital expenditures in the first quarter of 2022 were $3.6 billion, which included the acquisition Navitas Midstream, $275 million of organic growth capital projects and $75 million of sustaining capital expenditures. For 2022, we currently expect growth capital investments to be approximately $1.5 billion and sustaining capital expenditures to be approximately $350 million. Our total debt principal outstanding was approximately $29.8 billion at the end of the quarter. Assuming the final maturity of our hybrids, the average life of our debt portfolio is approximately 21 years. Our average cost of debt is 4.3%. And at March 31, approximately 95% of our debt was fixed rate. In February 2022, we repaid all of the maturing $1.4 billion of senior notes DD and CC using cash on hand and proceeds from the issuance of short-term notes under our commercial paper facility. Our consolidated liquidity was approximately $3.9 billion at March 31, including availability under our credit facilities and $231 million of unrestricted cash. Since the close of the first quarter, we elected to terminate a $500 million delayed draw term loan, which had not been utilized. Reported adjusted EBITDA was $8.4 billion for the 12 months ended March 31, 2022. Our consolidated leverage ratio was 3.4x after adjusting for -- after adjusting debt for the partial equity treatment of our hybrid notes and also reduced by cash on hand. And with that, Randy, I think we can open up for questions.

Okay. Randy, thank you. Tanya, we're ready to take questions from our audience.

[Operator Instructions]. And our first question comes from Colton Bean of Tudor, Pickering & Company.

So just starting off on petchem, realizing jumping ahead a bit here to Q2, but it looks like some of the spreads have gapped higher over the last months, so specifically, butane to iso and then MTBE. Can you just remind us of your ability to capture those spreads in butane and octane businesses and whether any profit or any earnings uplift might be sustainable? Chris D’Anna: Colton, this is Chris D’Anna. We're about 75% hedged. So we realize the benefit of what we're not hedged on. And that 75% is throughout the remainder of this year.

Got it. And is that true of both the butane and the octane businesses? Chris D’Anna: That's just the octane business. And we still realize any benefits from uplift in the market as well.

Okay. Great. And then just on the balance sheet, Randy, any updates to how you're thinking about the leverage profile? It seems like with the current earnings trajectory and commodity backdrop, you're likely to drop below the lower end of that target range at 3.25 debt-to-EBITDA.

Yes. Well, Colton, again, we just finished with 3.4 for the quarter. Colton, we'll again stay in our range of 3.5x, plus or minus 0.25. And as we go through and see what kind of growth capital opportunities we have, what kind of acquisition opportunities that may be out there, we'll come in and adjust accordingly.

Got it. So it sounds like CapEx would be still the primary directive in terms of staying within that range?

Yes. I mean, Colton, we've come in and done buybacks for 4 years in a row. And the last 2 years, we've done about $200 million. I do expect for us to do buybacks later this year. We didn't do it in the first quarter because obviously, we had the $3.25 billion of Navitas. So we didn't do any buybacks in the first quarter.

Our next question comes from Brian Reynolds of UBS.

First, I wanted to touch on the Permian near-term growth expectations versus the long-term tightening outlook. We saw Midland to ECHO crude volumes decline quarter-over-quarter. I'm just curious if you could just talk about how Permian Basin MVCs and competition for spot volumes are impacting EPD's crude volumes? And ultimately, when could we expect EPD's Permian crude equity volumes to inflect back towards the positive or back towards positive growth in line with basin expectations?

This is Brent. I think on the volume, when you look at the structure in the market, there's some contracts, there's term contracts. But I think people are looking at the backwardation in the market and trying to figure out when those barrels come out on the other side. So we saw some contracted customers not shipped. And in terms of overall profitability, it doesn't really affect us with the nature of those contracts. The windows come back, I think you'll see when production growth and arb start opening back up, you'll see the volumes come back on our system. Yes. In terms of the profitability side, it's -- it doesn't really impact Enterprise. But in terms of volumes, how you look at it, when structure gets that backward, we did see some barrels come off our system.

Great. Makes sense. As one follow-up, maybe just to pivot to the 300,000 barrel per day expansion of Seaway that you talked about at the recent Analyst Day. The first question is, could you maybe just talk about the demand that you're seeing for this project given the demand markets in Houston and for export? And then secondly, do you see a scenario where just the increase in Canadian supply pushes back on Permian barrels flowing up into Cushing?

For you, Tug.

Tug, you want to take that?

Yes. This is Tug. The first answer to your question is with respect to the expansion, that's going to flange up with Enbridge's decisions upstream of Cushing with regards to the Canadian growth that those guys are seeing. So they're poised to turn that online as soon as they see the need to do that. And then for the second question, I'll pass that one back to Brent.

Yes. I think there's some sticky barrels that go from Permian up to Cushing just because of some of the refiners that want those barrels. My personal belief, and I've had this for quite some time as much capacity that we saw get pointed to the Gulf Coast. But ultimately, more of those barrels would fill the pipelines going toward the water. But we've seen some pretty good resilience even when we thought those barrels should have been pointed toward the water. There's a certain amount of demand up there in Cushing that will probably persist throughout this. And it's a different type of barrel than obviously what comes down from Canada that those refiners want up there.

Our next question comes from Jeremy Tonet of JPMorgan.

Just want to start off with the CO2 LOI as you guys press released recently. Mike, can I get a little bit more detail there as far as what kind of type of timeline would you expect, I guess, before a final investment decision, whether to move forward here? And just wanted to get a sense to the extent you're able to share how sizable could this project be. Hub could be a lot of stuff going on. And how much would be brownfield versus greenfield? Just any details there you're able to share would be very helpful.

Jeremy, it's Carrie Weaver. So on your first question on the details, we're looking at this as a complementary relationship with OLCV where we provide the transportation and they provide the sequestration. We've been talking to potential customers for several months now. And so these projects we see, they will take time to develop. But we've got a lot of great feedback from the customers. And believe as soon as they're ready to say go, we'll be able to move forward with the project. And the Gulf Coast is, I think, the most prime for a project like this with the emissions and the proximity of the emissions. And so we think there is a great opportunity in this area. And I think the second question as far as newbuild versus existing pipelines, if you take a look at our map, really any of the pipes we have could be put in -- most of the pipes we have we put in CO2 service whether that's in the gas phase or in the dense phase. And so it's just an evaluation of where we have those opportunities where we might have pipe capacity and then growing from there.

Got it. That's helpful. And then second question, just wanted to see with regards to Permian gas egress, you talked a bit about that at the Analyst Day. And obviously, there's -- seems there's clear need for that. I'm just wondering if there's any updated thoughts with the potential for Enterprise to expand existing assets like we've seen some other asset announcements recently or just any other thoughts on Enterprise's ability to partake in nat gas egress needs?

So we've -- we don't have any expansion capabilities on our existing 36-inch at 30-inch. But we're at looking opportunities to provide the basin with takeaway capacities. And then obviously, we've got some space open for ourselves, call it, middle of this year, end of the year that we talked about in Analyst Day.

Jeremy, I think what she's saying is yes, we've got a project. But no, we're not going to tell you about it.

Our next question comes from Chase Mulvehill of BOA.

I guess first question is just kind of around frac rates. I'm just kind of curious what you're seeing old frac rates today. Obviously, it seems like things are kind of tightening up there from a utilization standpoint. So I would kind of expect that frac rates maybe have moved off that $0.05 per gallon range. So just kind of any updates what you're seeing out there in the market on frac rates and maybe some utilization.

I'd say -- this is Brent Secrest. On frac fees, we are seeing fees trend up, and I'd say that's pretty much a general comment for a lot of midstream services. In terms of volume, volumes were a little bit down in the first quarter. A lot of that had to do with freeze-offs and turnarounds that we had scheduled that we moved up because of freeze-offs. But if you look at the projections of the Y-grade receipts we have coming in, it's going up pretty much month-over-month.

Okay. Sorry. And then pivoting over to ethane exports. I think in the press release, I think I read that the average ethane export fees increased in 4Q -- or sorry, in 1Q. I guess kind of curious what's driving that. I don't know if you -- I don't think you have commodity price exposure there, but maybe I'm wrong. So I don't know kind of -- is that new contracts? Or is it commodity price exposure that's driving those export fees up?

Chase, it's Justin Kleiderer. I'd say, in general, we've probably seen a trend in what spot volumes are available and the fees associated to those go higher than what we've seen over the last, call it, 12 to 18 months. But for the most part, the ethane export story is really a volume story.

Okay. Remind me again, how much -- what's your contracted versus spot on ethane export?

We call our kind of day-to-day capacity a shade over 200,000 barrels a day. So call it, we've got 20 to 25 a day as we sit here.

And our next question comes from Theresa Chen of Barclays.

Tug, I wanted to ask first about your Texas Western product system. You've been helpful in providing some color at Analyst Day about the capacity of origination, i.e., how many barrels per day you ship out -- ship up from the Houston area. But can we get a sense of the delivery capacity by market between the endpoints in the Permian, Albuquerque, New Mexico and Grand Junction? And where do you see the incremental demand coming from?

Sure. So I'll just take it by segment. Chaparral do up to full capacity of around 90,000 barrels a day. And then if you were to look at the Rockies segment, its full capacity could be up to 75,000 barrels a day. If you go to Albuquerque, as you drop barrels off there, the capacity will go down as you go further north towards Grand Junction. So the difference between those 2 numbers is what you'd be able to drop off in the Permian. And then sorry, what was the second question you had?

Just where do you see the most demand coming from of those 3 markets?

Yes. I think if you look at those markets and the fact that they need competition, I would say that Grand Junction, which is presently capped to local supply and rail, that will be a big step up in demand. However, it's not -- the market size is not as big as Albuquerque, for example. So it's going to be a combination of those and the Rockies in addition to supplying the Permian producers in the Delaware distillate as well on our gel terminal.

And I also wanted to ask about the downstream implications from the ethane perspective, kind of going back to the question. But seeing the supply chain logistical issues on the polymer side and the economic run cuts we're seeing at some of your customers, I was just curious how do you see this play out? And maybe Chris can help shed some light on the next steps from here.

Yes. I'd say, from the ethane balancing point, we're starting to see a slight build of ethane in our storage system. So as you see depressed natural gas prices in the Permian Basin, you see more ethane get recovered out of that area. And you look at the NGL volumes that you've seen step up on our system, ultimately, I think there's going to be some gives and takes on the petchem side until these things get worked out and for it to work on a more fluid basis. I just think you're going to see starts and stops throughout the process.

This is Jim. I think you're definitely seeing the supply chain somewhat concentrated. You're right, we're realizing some economic run cuts in ethylene plants as they're stacking up polyethylene. But that ultimately gets resolved. And this is still the most price-advantaged market in the world.

And our next question comes from Jean Ann Salisbury of Bernstein.

How will Enterprise be affected if the Permian does out of gas takeaway in the next year across your different segments? And would you expect the net result on EBITDA to be positive or negative if that happens?

Jean Ann, Brent has been stressing out over what question you would ask. So we're going to let him answer.

I mean I think the benefits, Jean Ann, I'm not going to sit here and quantify how this all plays out. But obviously, with the exposure we have on natural gas and that capacity at 300 a day, obviously, we're beneficiaries of it. If you go downstream to what I just talked about on the NGL pipelines, the amount of ethane that's going to be forced in the recovery, I think it's incredibly beneficial for our franchise on the pipeline segment coming out of there. If you go downstream from there and you look at fractionation, you look at the ethane dock, you look at our storage complex, I think there's a lot of ways for us to benefit as Enterprise. No different to the last question, it's not going to all work. We talked about that there's going to be opportunities. And there's going to be dislocations. And it's not going to go step by step. But ultimately, when stuff like that happens, and I've been around this company for a while, there's a lot of ways for Enterprise to benefit.

All right. And you feel good that it will probably at least offset losses and growth from NGL production there if that gets flared or shut in?

Yes, and we'll see how it all plays out. I mean we're seeing opportunities on our processing side to accommodate other computing processing companies to handle those volumes. So I just think when you look at our footprint, Jean Ann, if something like that happens and it gets delayed, I just think there's a lot of opportunities for us.

And you still had tender announced that they were going to expand the 2 gas pipelines by what, $400 million, $500 million a day each by the fourth quarter of next year. So I mean, yes, you're going to have some issues in the short term, but those things always get fixed.

Yes. And then as a follow-up, I think you had been expecting some material roll-offs in the Eagle Ford and South Texas this year. Is that looking a lot better now that Eagle Ford gas is already rebounding?

We've been expecting what? This is Tony. Say that again, Jean Ann.

I think that you'd kind of guided to expecting some roll-offs on rate in your South Texas and Eagle Ford system this year and next. But now it feels like we're kind of headed back to previous highs in the Eagle Ford. So I wanted to see if I should sort of take that out of my model.

Jean Ann, I mean, there's a big contract roll off on EFS that rolls off at the end of the second quarter. Those volumes are contracted. The volumes still contracted. It's long-term dedications to us. It's just at a different fee. I do say on the dry gas side and on the processing side, we're seeing some benefits throughout the entire Eagle Ford system. But from a total dollars perspective, you're going to see some impact for what rolls off on EFS.

Up on your plants in Eagle Ford, Natalie?

We're full, and we're actually restarting a plant that we decided now to spend capital on a couple of years ago. And then we don't talk about it a lot but we're processing over 400 million a day of lean gas today in the Eagle Ford. Customers are asking for treating capacity every day.

Our next question comes from Spiro Dounis from Credit Suisse.

I just had a follow-up to Colton's earlier question actually. Just thinking about sustainability of results overall rather than just petchem. About the rest of the year, you've obviously got some tailwinds here with Navitas ramping up some growth projects. You just mentioned a bit of a headwind there with some contracts rolling off. But I think about how you're tracking ready only 1 quarter in, you're sort of hitting that $9 billion run rate already that you guys had mentioned during the Analyst Day. So just curious, as you think about the rest of the year, what are you looking at in terms of puts and takes that maybe get you there?

Yes, we can do the math, Spiro. That was the answer.

I mean this is Brent. I think when you look at what we have going forward, I feel like we're in a pretty good spot. I mean things change. But when you look at where the pace and the trajectory of where this thing is going and the opportunities that we see before us, you can look at some contract roll-off, but it's not significant. I feel like what we're offering as a company, and you heard Tony talk about it during Analyst Day with the volumes that we see coming on, as things get more and more constrained, what we have to offer just goes up in value. So I know we don't give guidance. But in terms of the cadence, I feel pretty good about where we're at.

And our next question comes from Michael Blum of Wells Fargo.

Just really one kind of high-level question for me. And Jim, you referenced the 7 new projects you announced at the Investor Day. I think your forecast is pretty bullish for volumes underpinning a lot of those projects. So my question really is, how do you reconcile that with U.S. public E&P stands to remain capital disciplined in the face of high commodity prices?

Natalie, are we seeing our throughput go up?

Yes. The Delaware throughput has gone up. And we've been disciplined with the growth or with the builds of new plants. However, the private operators are drilling. And then we've got forecast from other operators that show we've got to have plant capacity. So that's what we're seeing. Delaware is full every day.

Zach, do you see in yours go up?

On the frac side -- this is Zach. On the frac side, we continue to see volume growth. And even the publics that are saying they're not growing or out trying to contract, whether it be spot volumes or shorter-term volumes, so I hear what they're saying, but what we are seeing, it contradicts it a little bit.

Yes. Michael, I'd also add that probably 70% -- between 75% and 80% of the rig count in the United States is Permian, Haynesville and Eagle Ford.

Yes. And then this is Tony, so I'll add one other thing. If you look at the weekly numbers by the EIA, they're showing somewhere between 200,000 and 300,000 barrels a day of increase since the 1st of the year. So these numbers are -- they are slowly inching up. If you look at the amount of rigs that very qualified operators have and still getting increased efficiencies out of them, they don't necessarily have to spend a tremendous amount of more money or put more tremendous amount of rigs out in the field to grow their production some. So we had said 1.5 million barrels between '22 and '23 not knowing exactly how it's going to fall. It looks like it's going to fall. Volumes won't start increasing until, call it, the third or probably even fourth quarter of '22 to where people really start looking. But we're absolutely seeing it everywhere in our system.

Yes. This is Tug. I'll just add, similar to the Zach's note, Natalie spoke to the equity production that she sees in the Enterprise has, but third-party volumes are continuing to increase as well. Using [Chinook] as an example, we had a record quarter, transporting just under 500,000 barrels a day, so going up.

Our next question comes from Keith Stanley of Wolfe Research.

I had 2 follow-up questions. First on the Texas Western products expansion. Just curious, since the Analyst Day, if you're seeing with conversations with customers any demand for long-term contracts there? Or if you think it will operate more on a spot basis? And then second question, just following up on, I guess, the petchem segment and the strength you saw in Q1. Just any more color you're seeing in the market in petchem? And how repeatable you think $400 million type margin quarters are in that segment this year?

It's going to be career limiting for Chris D'Anna if we don't see it. Do you have anything, Chris? Chris D’Anna: Yes. I guess second question first. I mean if you look at where spreads have gone, you see the normal has gradually widened throughout the first quarter. So looking for the rest of the year, it's pretty strong. Meanwhile, on the propylene side, spreads from the start of, call it, last year have marginally compressed. And I think I talked about last year how we expect to continue to see wider spreads as long as the supply chain issues persist. So I don't know if that helps. But...

All right. Back to -- this is Tug going back to your first question. I'll just say this. I think it's an understatement as far as how much interest we've received as we started talking to our customers on TW products. The interest has been significant. I will say that the rack market in nature is somewhat of a short-term market. Typically, those contracts are between 1 and 2 years. And quite frankly, I think there are certain things that we'd like to keep short in term in nature due to the spread and market opportunities in those markets.

Our next question comes from Michael Lapides of Goldman Sachs.

I know you've had Navitas only for a number of weeks now. But just curious -- and this may be a little bit of a follow-on from an earlier question, how different is the common carry kind of for end of '22 and through 2023 production growth you’re hearing from your Delaware producer customers versus your Midland ones?

When you say common carry, what are you referring to?

Meaning, when you're talking to your producers and they're talking about how much they want to grow, can you just talk about how different what you're hearing from producer customers are in the Delaware versus the Midland?

Well, put this way, Delaware has more majors. We're exposed of majors in the Delaware versus Midland. Midland, more private. I would say most have said flat to grow. But then when we get production forecast, they look a little bit different. And then in Midland, we have a lot of want for unloads from other processors. There's quite a few people still flaring in Midland, but not too much different other than a typical private public type of story.

Got it. And then turning to the ethane export facility. You talked about at the Analyst Day and it's a couple of years out from trying to think about COD. But just curious how capital-intensive of a project? And what are some of the milestones we should be monitoring kind of as analysts or investors, just to kind of track where you all are in terms of signing up contracts if you're going to try and fully contracted and just kind of take it from something that's on the drawing board to something that's in operation?

We have a contract for that expansion. So we have a pretty good size banker just to pick up.

Yes. I think as we talked about in the Analyst Day, I think the key path right now is just site location. And I think once we determine that, then it's about pulling trigger. I mean we're committed to build it. And [EOS] has backed it. And as soon as fine-tune our location, then we're going to be going on.

And we have numerous conversations going on with others.

Our next question comes from Michael Cusimano of Pickering Energy.

I have a few follow-on questions. First, relating to your commentary on Jean Ann's question, can you quantify how much ethane you're seeing or rejected in your primary systems today you can get an idea as to what that upside looks like in a Waha blowout?

In Permian?

Total across all Permian Basin, it's probably around 250, even some of it's hard to be recovered and some of it's non-integrated type plants. 200 to 250, Tony?

I agree with that, yes.

Okay. And that's as of today that's trajecting?

Well, it's -- over the last few weeks, it comes and goes because midstream operators, like ourselves, step in when we can. So...

Okay. That's helpful. And then to follow on from an export question earlier, can you talk through the dynamics you're seeing across the docks on rates and demand? You pointed to lower fees at EHT on the NGL side, but higher on crude and then the commentary around Morgan’s Point. Just curious from a high level how maybe any flows might be shifting on system as well as, yes, commentary around rates would be helpful.

Yes. I mean I think every commodity has its dynamics. But at the end of the day, similar to our commentary from Analyst Day, I mean, they're all going to have their day where supply starts to exceed that, which the industry can export. And so in general, we think the trend is up and to the right in terms of export fees.

And when you look at a U.S. barrel compared to everything else, there is no comparison. And we don't think there's going to be because we remain constructive on crude prices.

I am not showing any further questions at this time. The replay for this call is available until May 9 at 11:59 p.m. by dialing (855) 859-2056 or (404) 537-3406. The conference ID is 9788240. I would now like to turn the conference back to Mr. Randy Burkhalter for closing remarks.

Thank you, Tanya. That's all. That concludes our remarks today. So we'd like to thank all of our participants for joining us, and have a good day. Goodbye. Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.