Good day, and thank you for standing by. Welcome to the Enterprise Products Partners LP earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. Please be advised that today's conference is being recorded. To ask a question during the conference, please press star one on your telephone. If you require any further assistance during the call, please press star, then zero. 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 Partners conference call to discuss our first quarter 2022 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise Products Partners's general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise Products Partners'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 to be correct.
Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I'll turn it over to you, Jim.
Okay. Thank you, Randy. We have 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 of 2020, COVID-19 shut everything down, and you 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.
In late February 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. 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 NGLs, and we're planning for growth. During our meeting, we announced seven growth projects related to both supply and demand. We're gonna build our sixth processing plant in the Midland Basin. That's the assets we bought from Navitas.
At the Delaware, we're gonna build our second plant at Mentone. In Louisiana, we're expanding our Acadian Haynesville natural gas pipeline, about 400 million cubic feet 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 gonna build our 12th NGL fractionation train. We announced that we're gonna 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. Then shortly after the analyst meeting, we issued a press release with Oxy, stating that Oxy and Enterprise were gonna team up to build a carbon capture sequestration header system between Beaumont and Houston.
Combined, these projects we have announced will still fall within the $1.5 billion-$2 billion annual CapEx. I wanna end today 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 replace Russia's exports of oil products and natural gas to our European allies if we would unleash the God-given shale resources that we are 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 finding and producing these resources isn't on autopilot. Take 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 the foul 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 of 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 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 unit holders 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 non-cash asset impairment charges of $14 million or 0.01 per unit for the first quarter of this year. This compares to non-cash asset impairment charges of $66 million or 0.03 per unit in the first quarter of 2021. Jim discussed distributable cash flow and coverage. Moving on to adjusted cash flow from operations, which is 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 of 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 12th to our common unit holders of record as of the close of business April 29th. 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 it 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 of 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 BB 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 3.4 times after adjusting debt for the partial equity treatment of our hybrid notes, also reduced by cash on hand. With that, Randy, I think we can open it up for questions.
Okay, Randy, thank you. Tanya, we're ready to take questions from our audience.
Certainly. As a reminder, to ask a question, you need to press star one on your telephone. To withdraw your question, please press the pound key. Please limit your questions to one and a follow-up. One moment. Our first question comes from Colton Bean of Tudor, Pickering, Holt & Co. . Your line's open.
Morning. 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 month. Specifically, butane to isobutane 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?
Hi, Colton. This is A.J. 'Chris' D'Anna We're about 75% hedged, so we realize the benefit of what we're not hedged on. That 75% is throughout the remainder of this year.
Got it. Is that true of both the butane and the octane businesses?
That's just the octane business.
Okay. On
We still realize any benefits from uplift in the market as well.
Okay, great. Just on the balance sheet, Randy, any updates to how you're thinking about the leverage profile? You know, 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.
Yeah. Well, Colton, you know, again, we just finished with 3.4 for the quarter. You know, Colton, we'll again stay in our range of 3.5x ± a quarter. As we go through and see what kind of growth capital opportunities if we have, what kind of acquisition opportunities that may be out there, we'll come in and adjust accordingly.
Got it. It sounds like CapEx would be still the, you know, the primary directive in terms of staying within that range.
I mean, Colton, we've come in and done buybacks for four years in a row. You know, the last two 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. We didn't do any buybacks in the first quarter.
Great. Appreciate the time.
Thank you. Our next question comes from Brian Reynolds of UBS. Your line's open.
Hi, good morning, everyone. First, 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. Was curious if you could just talk about how Permian Basin and MVCs and competition for spot volumes are impacting, you know, EPD's crude volumes. You know, ultimately, when could we expect EPD's, you know, Permian crude equity volumes to inflect back towards the positive or back towards positive growth in line with Basin expectation? Thanks.
Hey, this is Brent Secrest. 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. We saw some contracted customers not ship. You know, in terms of overall profitability, it doesn't really affect us with the nature of those contracts. When those come back, I think you'll see when production growth and arbs start opening back up, you'll see the volumes come back on our system.
You're getting taken back, aren't you?
Yeah. In terms of the profitability side, 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? Thanks.
You and R.D. 'Tug' Hanley. R.D. 'Tug' Hanley, you wanna take that?
Yeah, this is R.D. 'Tug' Hanley. The first answer to your question is with respect to the expansion, that's gonna flange up with Enbridge's decisions upstream of Cushing with regards to the Canadian growth that those guys are seeing. They're poised to turn that online as soon as they see the need to do that. For the second question, I'll bounce that one back to Brent.
Yeah, I think you know, there's some sticky barrels that go from Permian up to Cushing just because of some of the refiners that want those barrels. You know, my personal belief, and I've had this for quite some time, is much capacity that we saw get pointed to the Gulf Coast, that 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.
Great. Thanks for the color. Have a great day.
Our next question comes from Jeremy Tonet of J.P. Morgan. Your line's open.
Hi, good morning.
Morning.
Well, just want to start off with the CO2 LOI, as you guys press released recently. If you might be able to 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, you know, whether to move forward here? Just want to get a sense to the extent you're able to share, how sizable could this project be? A hub could be a lot of stuff going on and, you know, how much would it be brownfield versus greenfield? Just any details there you're able to share would be very helpful. Thanks.
This is Carrie. Hi, Jeremy, it's Carrie Weaver. On your first question on the details, I know 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. You know, 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 primed for a project like this with the emissions and the proximity of the emissions. We think there is a great opportunity in this area.
I think the second question, as far as new build versus existing pipelines, you know, if you take a look at our map, really any of the pipes we have could be put in or most of the pipes we have could be put in CO2 service, whether that's in the gas phase or in the dense phase. 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. Thank you. Then the second question, just wanted to see with regards to Permian gas egress, you talked a bit about that at the Analyst Day, and obviously seems like 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.
We don't have any expansion capabilities on our existing 36-inch and a 30-inch, but we're looking at opportunities to provide the basin with takeaway capacity. 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.
Got it. All right. Makes sense. Thank you for the thoughts. I'll leave it there.
Our next question comes from Chase Mulvehill of BofA. Your line is open.
Hey, good morning. I guess first question, just kind of around frac spreads. Just kind of curious what you're seeing on frac spreads today. You know, obviously it seems like things are kind of tightening up there from a utilization standpoint. Would kind of expect that frac spreads maybe have moved off that 0.05 per gallon range. Just kind of any updates what you're seeing out there in the market on frac spreads and maybe some utilization?
I'd say this is Brent Secrest. On frack 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 or that we moved up because of freeze-offs. 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. You know, pivoting over to ethane exports. I think in the press release, I think I read that the average ethane export fees increased in 1Q. I guess kind of curious what's driving that. I don't know. I don't think you have commodity price exposure there, but maybe I'm wrong. I don't know, kind of, is that new contracts or is it commodity price exposure that's driving those export fees up?
Hey, Chase Mulvehill, Justin Kleiderer . I'd say in general, we've probably seen a trend in what spot volumes are available and the fees associated with those go higher than what we've seen over the last, call it 12-18 months. For the most part, the ethane export story is really a volume story.
Okay. Remind me again, what's your contracted versus spot on ethane exports?
We call our kinda day-to-day capacity a shade over 200,000 barrels a day. Call it we've got 20 to 25 a day as we sit here.
Okay. All righty. Perfect. I'll turn it back over.
Our next question comes from Theresa Chen of Barclays. Your line is open.
Good morning. Tug, I wanted to ask first about your Texas Western Products system. You've been, you know, helpful in providing some color at Analyst Day about the capacity at origination, i.e., how many barrels per day you can ship out, ship up from the Houston area. 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. I'll just take it by segment. Chaparral could do up to, you know, full capacity around 90,000 barrels a day. 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. The difference between those two numbers is what you'd be able to drop off in the Permian. Sorry, what was the second question you had?
Just where do you see the most demand coming from, of those three markets?
Yeah. I think if you look at those markets, and the fact that they need competition, I would say that Grand Junction, which is presently captive to, you know, local supply and rail, that'll be a big step-up in demand. However, the market size is not as big as Albuquerque, for example. It's going to be a combination of those and the Rockies, and then in addition to supplying the Permian producers and the Delaware Basin as well on our Jal terminal.
Thanks. I also wanted to ask about the downstream implications from the ethane perspective, kind of going back to that FAFCI question. Just seeing the supply chain logistical issues on the polymer side and the economic run cuts we're seeing, you know, at some of your customers. I was just curious, how do you see this, you know, play out? Maybe, you know, Chris can help shed some light on the next steps from here.
Yeah. I'd say from the ethane balancing point, you know, we're starting to see slight build of ethane in our storage system. 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 pet chem 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.
I think this is Jim. I think you're definitely seeing the supply chain somewhat constipated. You're right. We're realizing some economic run cuts in ethylene plants as they're stacking up polyethylene. But that ultimately gets resolved. This is still the most price-advantaged market in the world.
Thanks, Jim.
Our next question comes from Jeanann Salisbury of Bernstein. Your line's open.
Hi. Good morning. How will Enterprise be affected if the Permian does run out of gas takeaway in the next year across your different segments? Would you expect the net result on EBITDA to be positive or negative if that happens?
Hi, Jeanine. You know, Brent has been stressing out over what question you would ask. We're going to let him answer.
I mean, I think the benefits, Jeanann, I'm not gonna sit here and quantify how this all plays out. Obviously, with the exposure we have on natural gas and that capacity, that 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 gonna be forced into recovery, I think is incredibly beneficial for our franchise, on the pipeline segment coming out of there. Then 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 gonna all work, and we talked about that.
There's going to be opportunities, and there's gonna be dislocations, and it's not gonna go step by step. 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. You feel good that it will probably at least offset losses in growth from NGL production there if that gets flared or shut in?
Yeah. We'll see how it all plays out. I mean, we're seeing opportunities on our processing side to accommodate other competing processing companies to handle those volumes. 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.
You know, you still had Kinder Morgan announce that they were gonna expand their two gas pipelines by 450 million a day each by the fourth quarter of next year. I mean, yeah, you're going to have some issues in the short term, but those things always get fixed.
Yep. Thank you. As a follow-up, I think you had been expecting some material roll-offs in the Eagle Ford in South Texas this year. Is that looking a lot better now that Eagle Ford gas is really rebounding?
We've been expecting what? This is Tony Chovanec. 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. Now it feels like we're kind of headed back to previous highs in the Eagle Ford. 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.
Okay.
You know, those volumes are contracted. The volume's still contracted. It's long-term dedications to us. It's just at a different fee. I do see on the dry gas side and on the processing side, we're seeing some benefits throughout the entire Eagle Ford system. From a total dollars perspective, we're, you know, you're gonna see some impact for what rolls off on EFS.
How full are your plants in Eagle Ford, Natalie Gayden?
We're full, and we're actually restarting a plant that we decided not to spend capital on a couple of years ago. 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 and customers asking for treating capacity every day.
Great. Thanks everyone for taking my questions.
Thank you. Our next question comes from Spiro Dounis from Credit Suisse. Your line's open.
Thanks, operator. Morning, team. Just had a follow-up to Colton's earlier question, actually. Just thinking about sustainability of results overall, rather than just pet chem. Thinking 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. I think about how you're tracking already only one quarter in, you're sort of hitting that $9 billion run rate already that you guys had mentioned during the Analyst Day. 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?
Yeah, we can do the math. Let's figure out. Who wants to answer?
I mean, this is Brent. I think when you look at what we have going forward, you know, 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, the opportunities that we see before us, you can look at some contract roll-off, but it's not significant. You know, 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. I know we don't give guidance, but in terms of the cadence, I feel pretty good about where we're at.
Perfect. That's all I had today, guys. Thank you.
Our next question comes from Michael Blum of Wells Fargo. Your line is open.
Thanks. Good morning, everyone. Just really one kind of high level question for me. Jim, you referenced the seven new projects you announced at the Investor Day. I think your forecast is pretty bullish for volumes underpinning a lot of those projects. My question really is, how do you reconcile that with U.S. public E&P stance to remain capital disciplined in the face of high commodity prices? Thanks.
Natalie, are we seeing our throughput go up?
Yeah. 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 forecasts from other operators that show we've gotta have plant capacity. So that's what we're seeing. Delaware is full every day.
Zach Seifried, you seeing yours go up?
On the fracs side. This is Zach Seifried. On the fracs side, we're continuing to see volume growth. Even the publics that are saying they're not growing are out trying to contract, whether it be spot volumes or shorter-term volumes. I hear what they're saying, but what we are seeing, and it contradicts it a little bit.
Yeah, Michael, I'd also add that probably between 75% and 80% of the rig count in the United States is Permian, Haynesville, and Eagle Ford.
Yeah. This is Tony. I'll add one other thing. If you look at the weekly numbers by the EIA, they're showing somewhere between 200 and 300 thousand barrels a day of increase since the first of the year. These numbers 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 a tremendous amount of rigs out in the field to grow their production some. We had said 1.5 million barrels between 2022 and 2023, 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 2022 to where, you know, people really start looking. We're absolutely seeing it everywhere in our system.
Yeah. This is Tug. I'll just add similar to Zach's note. Natalie spoke to the equity production that she sees and that Enterprise has, but third-party volumes are continuing to increase as well. Using Shinook arbs as an example, we had a record quarter, transporting just under 500,000 barrels a day, so it's going up.
Thank you, everybody. Appreciate it.
Our next question comes from Keith Stanley of Wolfe Research. Your line's open.
Hi. Good morning. I had two 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'll operate more on a spot basis. 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? Thank you.
It's going to be career limiting for Chris D'Anna if we don't see it. Anything, Chris?
Yeah. I guess second question first. I mean, if you look at where spreads have gone, you see the normal RBOB has gradually widened throughout the first quarter. Looking for the rest of the year, it's pretty strong. Meanwhile, on the propylene side, spreads from, you know, the start of, call it, last year, have marginally compressed. I think I talked about last year how, you know, we expect to continue to see wider spreads as long as the supply chain issues persist. I don't know if that helps, but...
All right.
Okay. Thanks.
This is R.D. 'Tug' Hanley. Going back to your first question, you know, 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 one and two years. Quite frankly, I think there's certain things that we like to keep short in term in nature due to that spread in market opportunities in those markets.
Thank you.
Thank you. Our next question comes from Michael Lapides of Goldman Sachs. Your line's open.
Hey, guys. Thank you for taking my question. 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 commentary kind of for end of 2022 and through 2023 production growth are you hearing from your Delaware producer customers versus your Midland ones?
When you say commentary, what are you referring to?
Meaning when you're talking to your producers and they're talking about how much they wanna grow, can you just talk about how different what you're hearing from producer customers are in the Delaware versus the Midland?
Well, let's put it this way. Delaware has more majors or we're exposed to majors in the Delaware versus Midland.
Mm-hmm.
Midland, more privates. I would say most have said flat to grow, but then when we get production forecasts, they look a little bit different. In Midland, we have a lot of want for onloads from other processors. There's quite a few people still flaring in Midland. Not too much different other than a typical private-public type of story.
Got it. Turning to the ethane export facility you talked about at the Analyst Day, and it's still a couple years out from trying to think about COD, and 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 y'all are in terms of signing up contracts, if you're gonna try and fully contract it and then just kind of take it from something that's on the drawing board to something that's in operation?
Yeah. We have a contract for that expansion, so we have a pretty good size anchor. Justin, pick it up.
Yeah. I think as we talked about in the Analyst Day, you know, I think the key path right now is just site location. I think once we determine that, then it's about pulling the trigger. I mean, we're committed to build it and INEOS has backed it. As soon as we fine-tune our location, then we're gonna get going on it.
We have numerous conversations going on with others.
Got it. Thanks, guys. I'll follow up offline.
Thank you. Our next question comes from Michael Scialla of Pickering Energy. Your line's open.
Hey, good morning. I have a few follow-on questions. First, related to your commentary on Jean Ann's question, can you quantify how much ethane you're seeing rejected in your Permian system today so we can get an idea as to what that upside looks like in a Waha blowup?
250.
In Permian?
Total across all Permian basins, probably around 250. I mean, some of it's hard to be recovered and some of it's on a integrated type plants. 200-250, Tony?
I agree with that. Yes.
Okay. That's as of today that's rejected?
Well, it's, you know, over the last few weeks, it comes and goes because midstream operators like ourselves step in when we can, so.
Okay. That's helpful. 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 Enterprise Hydrocarbon Terminal on the NGL side, but higher on crude, and then the commentary around Kinder Morgan's point. Just curious, you know, from a high level, how maybe any flows might be shifting on its system as well as the commentary around rates would be helpful.
Yeah. 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. In general, we think the trend is up and to the right in terms of export fees.
When you look at a U.S. barrel compared to everything else, there is no comparison. We don't think there's going to be because we remain constructive on crude prices.
Got it. That's helpful. Thank you.
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. We'd like to thank all of our participants for joining us and have a good day. Bye. Thank you.
Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.