Enterprise Products Partners L.P. (EPD) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by, and welcome to the Enterprise Products Partners ESG and Analyst Day Q&A. [Operator Instructions] I would now like introduce your host for today's conference call, Mr. Randy Burkhalter, you may begin.

Thank you, Kevin. Good afternoon, everyone, and welcome to the Enterprise Q&A call. This is a follow up to, as Kevin said, to our ESG and Analyst Day. We have a number of members of management here today to respond to your questions. Before we start the Q&A call, I must make some forward-looking statements here. So 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 that may be made during this call. And so Kevin, with that, we're ready to take questions from the audience.

[Operator Instructions] Our first question comes from Jeremy Tonet with JPMorgan.

I just wanted to kind of pick up, I guess, you guys talked about your outlook for rationalizing assets across your asset base there. And just wondering if you could expand a bit on that, I guess, what deepened the decision of retiring? Or also, could these plants be easily brought back if activity picks up? Or could they be moved to a different basin if activity there warrants it? Or how do you think about, I guess, asset sales in this environment for some of those? Just building on the part of rationalizing the asset base there?

This is Natalie Gayden. So I did speak to rationalization of assets in the presentation. And we're always looking to make sure that our production profile aligns with the processing facilities that we have in service. Our processing facilities to bring back our next-day type of plans, and Graham can probably expand on this, but they are quicker than what you would think of a refinery or petrochemical complex.

Yes. Just to add to that, it's not a big effort to bring many of these plants back or, in some cases, to relocate them.

Got it. That's helpful. And if I think about the petchem side of your business, there's been expansion there in this notable part of your existing program focused on petchem complex, PDH, what have you. Just wondering if -- how you think about how that fits into the portfolio overall? Is there a certain kind of limitation that you think it would represent within your EBITDA, overall, just given how it seems it's a bit more capital-intensive? Some of these assets are a bit more delicate or could go offline and some of the petchems trade at a little bit lower multiple than what midstream trades at, so just wondering how you think about that balance within your portfolio. On the other side, you do have very strong barriers to entry there.

Yes. Jeremy, this is Chris D'Anna. I talked a little bit about our growth in the recordings. And we see a lot of growth opportunities in that. So I don't know that we have a defined set of ratio on what the EBITDA will be in the future versus the rest of Enterprise. We do have a goal of over $1 billion by 2024 for the petchem segment. But we see a lot of opportunities. And as long as those are good returns, we plan to continue to pursue them.

Yes. Jeremy, this is Jim. In terms of multiples, this -- we're not an ethylene -- we don't have crackers. We don't have polyethylene, polypropylene plants. We're more of a midstream entity as it relates to petrochemicals. And when you look at it, just like it is with the crude oil or natural gas or NGLs, if you look at our PDH plant and the one we're building, those are totally in arrangements with investment-grade customers. If you look at our PGP plants, they are pretty much, I guess, Chris, pretty much all termed up.

Yes.

So we like the business, but we also like the way we can structure contracts within that business that are more, I guess, it was PDH plants where are there really annuities.

Our next question comes from Jean Ann Salisbury with Bernstein.

A lot of investors think Haynesville could quickly get constrained again even after all the pipeline expansions, including yours, given the rig count there. How much more capacity out could you easily add? And how long would it take?

Jean Ann, this is Randy. Which asset were you referring to?

The Haynesville.

The what?

The Haynesville.

Haynesville.

So as far as the capacity that we've got out of the Haynesville...

You're full, aren't you?

I'm full for the next 10 years. I know there's some pipes coming on, maybe 1 or 2 more. And after that, we'll see. But there's been a lot of talk about more pipes in the ground. We'll see what happens. But we're full for the next 10 years plus.

Okay. And if you did want to add a new pipe, it'd be kind of like 18 months, 24, I guess? I guess it's much easier to build there, it seems like, than other places?

Yes. Exactly. I'm from Louisiana. I guess that's why.

Okay. And then this is a little more near term, I guess, in the Analyst Day, but it seems like about half of chemical plants and a lot of refineries are still starting up. I assume that any of these that your customers are declaring force majeure and probably not paying you. Can you give a sense of how material you expect the loss from the Texas where you used to be?

Who wants to take it? Chris, you want to take it from petchem?

Sure, yes. This is Chris D'Anna again. Just in terms of the petchem business, we had a planned outage of our PDH going on at the time. So that's not really impacted. And then with regard to our splitters and other businesses, we experienced downtime probably equal to our customers and have a little bit of makeup capability. So I don't expect it to really be a material impact.

Okay. Great. And then if I could sneak in one more quick one. I had a question about the Delaware processing. I really appreciated all the color in your slides today, Natalie. Does the overbuild of capacity that you described in the Delaware put pressure on the rates that you can charge, both for processing and for downstream? Or when you describe the contracts as take-or-pay and acreage dedication, does that imply that the rates that you're getting are locked in for at least the medium term?

Yes. For the take-or-pay definitely locked in. And I sure hope that it continues to compress and get tighter for processing capacity. That's all good for us. Because it does exactly what you're talking about, rates move up. But as far as the take-or-pay that I discussed, I don't know, it's 70% of nameplate or more, definitely just a flat rate escalates for the next 10 years or more.

Our next question comes from Michael Blum with Wells Fargo.

I wanted to go back to the petrochemical segment for a minute. There was a comment made that you're looking at several transformational investments or potential transformational investments. And I think you said you're not going to say anything about it for another year. So the question is just can you, without -- obviously, not going to detail what these investments are, but can you sort of frame the size of them? Or how much capital you could possibly be talking about here? Just anything you could bucket for us in terms of the size of the potential opportunity?

We really can't, Michael. Not right now. These things are -- we're at a pretty sensitive point. And it's kind of like bass fishing with a worm. We got him bumping the worm. We still got to hook him.

Got it. Understood. Second question, I just want to ask about buybacks. So the question is really, do you ever think you'll get to a place where you would have a more programmatic buyback approach as opposed to opportunistic as -- not a fixed number per se, but maybe a percentage of discretionary cash flow, or something like that? And within that, how would you think about increasing buybacks versus increasing distribution?

Yes, Michael, yes, I mean, you never say never, right? So I mean, could we get to the point of a programmatic buyback? We could. How we would think about it, a programmatic buyback versus distributions, some of it would depend on the facts when we get to that point. And I'll still come back the most efficient way to come in and return capital in an MLP is to come in and do it through distributions. And whether the distributions are regular distributions, or whether distributions are special distributions, it's the most tax-efficient way to get cash in the pocket of limited partners. And the nice thing about the buybacks is you're not locked into an amount like you would be with a regular distribution. But I would really just have to depend on what the fact said is at the time and what the other opportunities are, but just -- it's really fact-specific once we get to that point.

Our next question comes from Keith Stanley with Wolfe Research.

One follow-up on petrochemicals. And I know you don't want to talk to specific projects, but at a high level, can you give a sense of some of the opportunities you're seeing in the next few years are in similar areas of the petchem business where you already operate? Or could you look to broaden your position in petchem? And I guess, relatedly, are acquisitions a possibility in that business as well?

I guess acquisitions are always a possibility, but that's -- we're not working any right now. We -- if you're asking are we going to build an ethylene plant, the answer is no. If you're asking are we going to stay in the wheelhouse we're in, the answer is yes.

Okay. Unrelated one, on the LPG export contract data that you disclosed today, so Slide 44. Can we think of the contracts from 2015 and earlier as kind of the higher-priced legacy contracts that you still have? And then for the more recent contracts or the lighter blue bars, any sense of where rates are on those? Are they pretty close to market overall?

I'd say -- so I think that's a fair way to look at on those legacy contracts. I'm trying to get to the slide.

Brad, jump in?

Yes. I was going to say that, that is a good way to think about it. I mean as we think about expansions and how they're priced and the underlying economics of those relative to -- as those original contracts roll off, we price it at a market-based rate. And I think we've stated in the past that we're going to stay aggressive and stay full on the export docs, and I think you'll see us continue to do that.

Our next question comes from Tristan Richardson with Truist Securities.

Just a question on the processing side. You noticed -- you noted in your presentation that a diverse exposure between public and private producer-customers in the Permian. Can you elaborate on that a little bit? I think we're generally hearing comments out there that private producers may be increasing activity at a higher rate than public peers. But can you elaborate there? Is that consistent with what you're seeing or the message you're talking about in the slide?

I think -- so that is consistent. I mean we meet with, obviously, all these guys, and I will just tell you that the public guys are -- they all are talking the party line. And it doesn't feel like they are going to be active drilling. I know there's some outliers that some folks kind of made statements in the earnings calls. But I'd say there is a party line for these public guys that they are not going to be active this year. And on the private guys, you can just see what the -- what this -- where the -- I forget what the percent is. Natalie or Tony?

45%.

45%.

Yes. And so when you look at the percent of the pie that the private guys are increasing, and that percentage just seems to go up every week, they are taking a different approach in terms of their activity level.

And then just a follow-up. Randy, in the prepared comments, you talked about evaluating repurchases through the lens of the free cash flow return opportunity. If consensus out there suggests that EPD units today represent a low to midteens-type of free cash flow yield opportunity. Can you frame that for us relative to the opportunities you're seeing out there for capital deployment, either inside the energy transition theme or not?

Yes. We -- Tristan, because, one, as far as the kind of types of returns on capital that we're seeing, we've -- over time, we said pretty much midstream projects. The bell curve on midstream projects are at 10% to 15% unlevered returns on capital. And then once you sort of get outside that bell curve, then that's where you can come in and see some better returns. And I think what we're looking at is sort of in that range. And then as far as what we're -- obviously, what we're seeing on cash flow yields, as you cited, are sort of low double-digit, low-teen type returns. And Tristan, I'll come back in, and Chris mentioned it in his remarks, the cash yields that we did buybacks for, if you come back and if you look back over the last 1.5 years, have really been in that, call it, 11% to 18% cash return on capital. And when we come back in and look at last year, with $200 million of buyback last year, the returns, obviously, were a little bit higher with what we saw there in the second and third quarter, just where the midstream sector was trading. And then one other thing I would add, and I think we -- and I tried to allude to it on the webcast that aired this morning, as far as our willingness to do buyback, I think we've demonstrated that. We came back in, in fact, some materials that some banks provided gave us a little bit more context that when you come in and you look at U.S. midstream companies in 2020, we represented 30% of the buyback volume that was done. So I think we'll be there. We'll compare buybacks. We'll compare the organic growth capital opportunities that we have, and we'll go from there. But we're -- I mean, we -- I think we've demonstrated a willingness to come in and come in and do buybacks.

Our next question comes from Pearce Hammond with Simmons Energy.

My question today pertains to hydrogen. While recognizing that more meaningful hydrogen adoption is deeper into the future, just curious if you're receiving inbound phone calls from either integrated oil companies or industrial gas companies or some of the newer companies targeting the hydrogen market? Just curious if they're seeking storage space to store hydrogen and/or pipeline capacity to move hydrogen? So any color you can provide would be super helpful.

Yes, this is Jim. We got a call recently, and we haven't met with them yet, with a petrochemical company that is obviously looking at some hydrogen projects, and said they need a pipeline storage company. And I don't know what the hell they're talking about because we hadn't met with them yet, but we are going to meet with them.

Our next question comes from Michael Lapides with Goldman Sachs.

I actually have a couple at once. First of all, when you talk about transformational, should we think of it -- that's kind of a big word, right? Should we think of it as transformational, meaning midstream related but something that is not just, hey, I'm buying a $200 million asset-type thing. Or is it something that's kind of outside the traditional midstream sphere?

I think it's outside the box.

Okay. How do you think about your equity currency as a source of capital to utilize to do a sizable transformational change?

I don't know about you, but I don't think much of it.

Yes -- Yes. Michael, I think some of the things that we're looking at, I mean, we would not need to do equity financing.

Got it.

Yes. I mean -- I mean the way we look at equity, it's prohibitively expensive and somewhat scarce.

Got it. Okay. So it's something you could either finance with cash flow or financed by -- is there a cap on the amount of leverage you're willing to go to, to do a transformational acquisition?

Michael, I mean, we -- the investment-grade metrics are very important to us. And we -- frankly, that's one of the things we retain a lot of financial flexibility with, keeping leverage in that 3.5x area, that gives us a lot of leverage that you could make a sizable acquisition if we wanted to go that way and come in and, frankly, do it for cash and not be above 4x.

Got it. Yes, sure. You have a ton of balance sheet capacity.

Right.

A massive amount. Okay. Super helpful. One last one, you gave a lot of detail about how much of your Delaware G&P is on take-or-pay. Can you talk about the rest of your processing, right, because your Permian is just one piece. How much of the rest of your processing is on take-or-pay?

Not as much as we'd like. But a lot of the newer contracts that we get into, we have a -- we typically try to do a take-or-pay, although acreage dedications has become very popular this year. Obviously, up in the Rockies, as our legacy, a lot of those are life of lease legacy contracts that aren't necessarily -- they may have a fee base to them. Gulf of Mexico has some keyhole-type contracts, but they have -- some of them have a floor. So Permian is really probably one of the basins that we have the richest take-or-pay, flat fee-based type contracts that we really like. And we like to see -- we'd like to see all basins at that level. But some of them are legacy, and that's where they stand.

Got it. Much appreciated.

But when you do acreage dedications, I mean, it depends. There are some good things about acreage dedication.

Yes. There's great things about this dedication.

At least if I produce, you're going to get it.

That's right.

And the other thing is if you put in there that, hey, I get the first $100 million or $200 million, you've really improved your lie, even though you call it an acreage dedication.

Right. We do a lot of first dedications, meaning, we get the first x out of this area. Tony's team, our fundamentals team, does a really good job of validating producer curves in the rock. So we do a lot of homework before we just go sign acreage dedication in specific basins up. But it needs to be a basin that we like and that we're confident that will be around for a while.

[Operator Instructions] Our next question comes from Christine Cho with Barclays.

So actually, if I could also tack on a question about the Delaware G&P portfolio. The slide indicates that the private producers are the ones who are contracted through acreage dedications. And so if these are the folks that are actually increasing activity while the public players are being more disciplined, would this imply that this is where upside to cash flow could materialize this year? I'm also assuming that it's any liquids that come out of the plants, you'd also be taking it all the way downstream. But if you could confirm that.

Yes, you're right. Any gas that we gather and process, it is connected to enterprise pipelines and fractionators. And you're absolutely right, these guys that we've exposed ourselves to on acreage dedications are drilling. And we meet with them pretty often. We're rooting for them. But the same thing goes there, though, we look at the rocks. And a lot of -- we've done a really good job to make sure there's not a whole lot of capital spend to even get to them. So really short -- short lays of pipe, but maybe just a meter.

And if you could also -- I mean what are the producers doing with respect to hedging like the private players? Just because the curve is so backward-dated, so are you seeing them hedge at all? Or is it really nothing?

Christine, this is Tony. It's really hard to know what the projects are doing. But if they are in the markets -- in the capital markets at all, what we hear from them is they are hedging a substantial portion of it out for 3 years.

And maybe if they're PE backed, they're probably hedged.

Yes. If their PE backs are probably hedged, and frankly, the curve probably tells some kind of profitability. There is -- these kind of numbers they ought to hedge. So we think, and we connect those dots, and that's probably what they're doing.

Okay. And then if I could also then move over to the Midland-to-ECHO capacity side. You have a line here for optimal capacity and then another for max capacity. And I appreciate you've contracted over 90% of the optimal line. But to get from optimal to max, I'm assuming that's done with more pumps or DRA. And I'm guessing the marginal cost goes up when you do that. So how do we think about what the spreads or the fees need to be for it to make sense to increase to that level? Am I correct in thinking that the fee needs to be higher than what the current contracted rate is?

This is Brad Motal. It's kind of difficult to answer that question because we operate those 3 pipelines as one. And as we get different volume profiles from each of our outlier underlying contracts, that kind of changes the fee structure or the cost across the pipes. I'll tell you, you hit the nail on the head right out of the gate. It's DRA and additional horsepower to get to that peak throughput. But that 1.2 million barrels is kind of the -- that's where the price for any incremental -- incremental barrel across any one of those 3 pipes starts to touch to creep up. But it's hard to explain that when it really depends on the contract mix at that given time.

This is Brent. I'll just add, look, we have a graph, and we can tell you to the penny what barrel, 1 million to 1,005,000 cost us to move. And so we look at that every single day. And if there's economics to move the barrel, the net barrel gets moved. So obviously, as that pump curve goes up, the costs go up. And you're right, it's DRA, and it's running pumps harder and it's -- those are the things that we're looking at on the expense side.

And DRA is not cheap.

Okay. And then I guess, just given the overcapacity in the Permian, what would make you feel like you have the opportunity to leave the max capacity levels?

Something materially would have to change for that spread to widen out, and whether that's some pipeline or pipelines to get repurposed, or whether these guys go back in the basin in a big way and start drilling. But it's hard for me to see a point in time any time soon where that does happen.

Okay. Just wanted to make sure.

Our next question comes from Timm Schneider with Citi.

And thanks for all the information. 2-part question here. First of all, look, I think a couple of the buzzwords that we heard, transformational, and then Jim, I think you just said outside the box, how do we think about enterprise 5 years from now? And I'm not looking for numbers, guidance or anything like that, just -- it seems like it's a continued shift away from the wellhead. So how would you kind of describe that?

Timm, I've already made myself a note, never to say transformational and never to say outside the box again. I think you're going to see us continuing to do what we've always done, in my mind. We're going to continue with this midstream model. More that midstream model may be directed at petrochemicals, but we're not going to lose sight of where it all starts, which is at the wellhead. So I don't know, you probably just see us getting a little bigger in what we do. What do you think, Randy?

I mean, you're not going to see us produce a polyethylene or polypropylene, ain't it? And well, I guess, you said never say never, right?

Not in my lifetime, which could mean 5 years from now.

Got it. And then maybe as a follow-up to that, as -- and the reason I'm asking this is because it's come up on calls with some of your peers. Does this -- and I don't want to say transformational, I'm not going to use it, but does this shift have any impact on your structure down the road, right? And then what I'm specifically referring to is, obviously, as a bellwether here, a shift potentially to a C-corp. It sounds like you guys have a lot more CapEx opportunities than some of your peers, which could help on the tax aside. How do you guys think about that, especially if it is attracting a little bit more of a newer investor base that's looking at infrastructure in general?

Okay. Yes, Timm, I think within Enterprise's and MLP, we have a great deal of flexibility. First, treasury came in over a 2-year time period and revisited the definition of qualified earnings, I want to say that was probably 2017, 2018. And frankly, came in, and when they came back in to review the definition, broadened the definition as a result. And if anything -- and again, Jim said never say -- or how far we would go on the petchem side. But frankly, that gave Westlake more flexibility; and Williams, at the time, more flexibility with some of their petrochemical operations that they had. So that is qualified earnings under the -- in the 7704(c). When you come in and then if you look at how large we are and what our gross margin is, MLPs are allowed to have up to 10% of their gross margin be nonqualified-type activities. And you never want to get near the 10%. But still, even if we were 5% in that type number, that is a big number as far as what the implied EBITDA or gross operating margin would be associated with those nonqualified earnings.

Yes. Everything we're looking at doing, or falls under -- it's qualified earnings.

Everything.

Which is I want to be careful because we might have customers on the line. We have no intention to go and beyond primary petrochemicals.

Okay. Got it. But I mean how do you look at the structure, though, in terms of just attracting a much larger pool of capital as a potential C-corp versus an MLP, given your size, especially?

Timm, I think that's still a function of where is the equity market appetite or the energy sector at the macro level. And I've come in, and when you come in and you look at how we've traded, how the midstream is traded, we really trade in parallel with the XLE, with the S&P energy sector. Now we're -- we have a better return than that sector because -- but we really trade in step with that. Certainly, you've seen that since the election in November. You've seen the rally in the XLE, you've seen the rally in midstream, and you've seen the rally in Enterprise. But as far as doing a capital raise, I think some of the activity that we saw in 2020 that a really popular C-corp had to come in and pay a big discount to last trade just to get $1 billion done. And I don't know if that's not much deeper of an equity market than what we have in the equity market. So again, I think a lot of it just comes back into how attractive is the energy sector macro to the equity capital markets.

Our next question comes from Ujjwal Pradhan with Bank of America.

Appreciate all the color you have provided so far today. I wanted to first ask on CapEx. In your presentation this morning, you had talked about potentially sanctioning energy evolution type of projects in 2021. And I think previously, you had mentioned '21 CapEx could move from the current $1.2 billion up to $2 billion. Is that going to be contingent on the size of discretionary free cash flow this year or independent of it?

No. As far as the size of our CapEx program, whether it's, again, we try to put bookends on it at between $1.6 billion and $2 billion. Really, that's independent of where our discretionary cash flow is. It really -- that just really came in to the timing of projects that are in the developmental phase.

Got it. Thanks for clarifying that. And second question on the ESG presentation from yesterday. You shared EPD's achievements in terms of emissions reduction -- CO2 emissions reduction per Boe, but we did not see any specific targets. Is there additional thoughts you could share on how much further reduction you could achieve and whether carbon -- carbon dioxide sequestration could be part of that? Maybe as part of your direct business or through partnerships or maybe even purchase of carbon dioxide offset credits like some other energy peers have done?

Okay. Let me try to take the first part of that. And then on the carbon sequestration, I guess, Graham, who will pick up on that. We've not set any objectives -- or the objective that we set on lowering emissions and emissions intensity is really that they're economic. So we didn't want to come out there and put an artificial number out there. Our view is let's do it economically where it makes sense for everyone. And so I mean, that's what we're focused on. So at this point in time, we've not put a subjective goal out there.

As far as the sequestration, we're looking at -- we do evaluate projects at this point. We don't have anything specifically developed in terms of sequestration. We continue to evaluate the technology and monitor advances in technology. There's a few smaller areas where we're looking at some CO2 capture for other industrial uses. But at this point, that's a relatively minor area, but one we continue to work at and develop and look for opportunities that might be right.

And I will say, there are a couple of initiatives that we're working on this year that would come in and both accomplish lower in emissions and emissions intensity. We just need to get progress a little bit further on that.

Very helpful. And maybe a quick one on your crude exports business. You had the helpful summary slide on LPG export contracts on Page 44. Could you discuss your latest contract profile for your crude exports business as well?

Yes, this is Brad Motal, again. I think I showed it on Page 23, I apologize. I think you rationalized a different pace number. But we're contracted out through 2023. And we've got a pretty good portfolio of long-range agreements. So in near term, we're looking pretty good.

Our next question comes from Yves Siegel of Siegel Asset Management Partners.

Just a quick question. Given the power outages in February, will that impact how you guys -- any changes in terms of operations or how you contract for power going forward?

I think one of the things we'll look at, obviously, in the Texas power markets, there's a lot of -- a lot up in the air right now from how ERCOT responds potential legislative action. We'll have to watch that and see exactly how we respond to that and how that might impact our contracting mix as far as power goes.

And operationally, any impact or any tweaks that you might make given that the power...

From an operational impact, it was really the operational impacts were all driven by price and not reliability in terms of our use of electrical power.

Our next question comes from Michael Cusimano with Heikkinen Energy.

I wanted to go back to the Permian and the asset optimizations that you are talking about. In terms of time line, do you see us having to wait for MVCs to roll off over the next 3 to 5 years for midstream operators to be forced to do something? Or do you think there's more proactive projects that we could see over the next year or 2 that could improve that environment?

I mean, I think as these contracts roll off, people are going to have to take a hard look at their assets, and we've done it on some of our assets that Natalie alluded to, and figure out whether they are truly profitable assets or whether they need to be in some other service. So...

Or somebody else's sand.

Right. Can somebody else do something else with it, that the person that owns it right now can't. So it's -- I mean, in my personal opinion, it's going to take time for this whole thing to shake out. But you can look at what pipelines are flowing or what plants are flowing or, in most cases, not flowing, and figure out who is exposed in this environment.

Got it. And then maybe staying there, you said that it could be more valuable in someone else's hands. We've seen some activity in M&A with G&P business maybe catching a bid to fill more downstream assets. Is that something that you see like a trend continuing as maybe there's less growth at the upstream level than what we expected a year or 2 ago?

I think you're talking about energy transfer in Enable?

Yes, sir.

Yes, that's a good question. We've looked at, should we do something like that. And frankly, at this point, what we believe is that our downstream system is a pretty good magnet for getting product in our pipelines upstream. And price matters. I'm not going to say we won't do it, but we won't do it at what these people expect to get today.

Sure. Yes, that's helpful. Okay. And then if I could ask one more on specifically, I appreciate the details you all laid out in the slide, but I guess, could you provide, I guess, your high-level expectation on Canadian production? Or maybe what you're hearing from your partner in that pipeline? And then a couple more specific questions, follow-up.

This is Tony. It's hard to make a case at this point, the Canadian production's is going to go down even with the Keystone XL ruin. Yes, pipelines incrementally to take more of that production away or getting tougher. Clearly, that bar continues to get raised. But don't forget that Canadians are masters, should take them crude up by rail if they need to. So -- and at these kind of numbers, their economics are very good, their economics are good for growth. And it's in the hands of people at this point that, that's what they do. That's their sandbox. So...

Got it. Okay.

It's not -- they're not huge numbers, but it's hard to make a case those numbers are going to go down.

Got it. And then specifically on the slide, you all said that there's a 90% utilization on that 9 50. It sound the heavy volume increasing over time, interesting. Is that -- should we expect 90% utilization today? And then it's just a shift moving to heavy as Canadian production grows? Is that the right way to read that slide?

Yes. That's fair. The Canadian -- this is Tug Hanley speaking. The Canadian heavy has offset some of the throughput that we lost on light. So it's backfilling it.

You just got to think about how much capacity that there's out of the Permian Basin going to Houston or going to Corpus. And historically, the pipelines that deliver a lot of those light barrels into Cushing were of Midland origin and that movement just -- it's just unnecessary now.

Our next question comes from Shneur Gershuni with UBS.

Most of my questions have been asked and answered. I just wanted to return back to the buyback question for a second. Have there been any thoughts or discussions around returning to the target that you had for 2020, about 2% of CFFO being directed towards buybacks or even potentially higher number? Or is it really just going to be market dependent as to how things flow for this year?

Yes. Shneur, this is Randy. Look, thank you for that question. I just want a seafood platter of.

Did he say from where?

Yes. Shneur, we really came into this year, not setting a target intentionally. And a little bit what we talked about on our earnings call for fourth quarter that really we wanted to come in and see how this year developed. Certainly, the first half of this year because it could go several different ways. We've really been encouraged with what we've seen as far as just, I think, broad economy and what we're seeing from just. If you would, GDP and some of the prospects for GDP, certainly where commodity prices have been getting off to a better start this year. But really wanted to come in and save that for a little bit later in the year, before we come in and try to provide any kind of update as far as what our thinking is this year.

That makes perfect sense and happy that I got you a free platter of seafood. Maybe as a quick follow-up question. I was just wondering if you can talk about the potential working capital release that you sort of talked about earlier in the prepared remarks earlier today. I mean,what kind of scale and size should we be thinking about in terms of a working capital release?

Yes, Shneur, this is Chris Nelly. As we talked about during the fourth quarter earnings call, we had about $750 million, $800 million of working capital utilized in 2020. And again, as we talked about, we mentioned earlier that as we get to the back half of 2021, we'll be more in a discretionary free cash flow positive area. So I think that's when you could probably assume that we see a lot of that working capital come back towards us. But again, it is going to be dependent upon markets because we are able to -- we look at those opportunities on a day in and day out basis, and we're able to shift that working capital around as necessary. Because generally, when we're using that working capital, it adds very high margins associated with it.

That makes perfect sense. And hopefully, Chris, I won you a platter as well, too.

No luck there.

The next question is a follow-up question from Jeremy Tonet with JPMorgan.

You just spoke a good deal of amount about the world's need for LPG imports in Asia. And I was just wondering what that means for the U.S., why -- how much export capacity -- LPG export capacity will be needed over time. Any sense on scale, timing and Enterprise's, I guess, large role in that?

We've got an expansion sitting on the shelf, if I'm not mistaken, Bob?

Yes, sir, that's correct.

We haven't pulled the trigger on it. I will say our LPG export stayed pretty much full off through this past year in the midst of a pandemic. Yes, I really think so, it probably depends on production growth, doesn't it? Or anything?

Yes. This is Brent. We -- Enterprise and a bunch of companies, we're traveling all over the world and showing what the production forecast was going to be from the United States. And Tony was out there saying this is what's going to happen, and there was another producer right behind us, saying this is what was going to happen. And so if you looked, there was a lot of investment made overseas in anticipation for what was going to happen over here. So from a demand side, I think a lot of our customers, frankly, are trying to figure out where all the NGLs are going to come from because they need them.

And I guess -- this is Tony, I'll add to that. You already see that in the relationship between LPG and crude and how it's moved up, and that's how bad they want it and need it.

Got it. That makes sense. Sorry?

This is Bob Sanders. It doesn't necessarily have to be an expansion that we make. The port of Houston has gotten a proved word of project to expand the width of the Houston ship channel, which will allow for incremental vessels to come in so you can increase the efficiency of the assets you've got.

Got it. That's helpful. And maybe just kind of a housekeeping question for Analyst Day. Wondering, for the overall business, what level of take-or-pay does EBITDA represent now? Any ballpark figures there? And just EBITDA breakdown by basin, just trying to get broad strokes of how Enterprise stands these days.

Jeremy, I tell you what, we'll follow back up with you because we actually have that number in a slide deck that we did in March a year ago, and I'm just drawing a blank right now as far as what it is.

I'll follow-up with you, Jeremy. This is Randy Burkhalter.

Our next question comes from Becca Followill with U.S. Capital Advisors.

One big picture, one minutia. On your ESG day yesterday, I appreciate all the comments there. One area where I've asked before is just on the G portion that you don't have an elected board. Do you have any thoughts on potentially transitioning to an elected board?

This is Jim, and I think no. And secondly, I think we have as good a governance as anybody in the business. And when your GP owns 32% of the common units, that's called alignment and good governance.

Well, that was emphatic. And the second one is on NGL inventories. When I look on your balance sheet, you've got about $1.9 billion of NGL in inventories versus $840 million in the second quarter. So I assume part of that was because of just the build with the hurricanes, but was part of it just building in anticipation maybe in a run-up of NGL prices where you guys might get some windfall this year on that?

If we had that much, we hadn't sold forward, Becca. And we think we're not going to build inventory and take price for risk. Is that right, Brent?

That's correct.

And then the last one is, do you guys have the technical ability when we have disruptions, like we had a couple of weeks ago, to sell ethane in the market is nothing?

We have a lot of technical ability, Becca.

Okay. But do you have the ability to sell ethane as methane?

To some extent.

Becca, one thing I will add on the governance deal. We went back in and looked at Magellan's ownership and before Buckeye announced their strategic alternatives, and we looked at their ownership. And they had independently elected directors for quite a few years, 10, 15 years. And really, our ownership and their ownership probably there was 85%, 90% overlap with their top 20 investors and our top 20 investors. So it doesn't appear that governance or MLP structure or certainly, the governance piece of it is making any kind of difference as far as ownership goes, just when we look at that group.

That's fair.

Becca, you see who gives the soft answer and who gives the hard answer.

Well, both are valuable.

All right. Kevin, this is Randy. With that, I think we will conclude our call today. And we'd like to thank our participants for your interest for dialing in for our ESG day in, and we'll stay and followed up with Q&A. And we're hoping maybe next year, we can do this in person. So again, thank you, and that concludes our call today. Have a good day. Goodbye now.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.