Enterprise Products Partners LP (EPD) 2019 Q2 法說會逐字稿

Good morning. My name is Jason, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Second Quarter 2019 Earnings Call. (Operator Instructions) Randy Burkhalter, VP of Investor Relations, you may begin your call.

Thank you, Jason. Good morning, and welcome, everyone, to the Enterprise Products Partners conference call to discuss earnings for second quarter. Our speakers today will be Jim Teague, Chief Executive Officer; and Randy Fowler, President and Chief Financial Officer of Enterprise's General Partner. 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'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 with that, I'll turn the call over to Jim.

Thank you, Randy. Before I get into the script, I wanted to acknowledge a person sitting directly to my left, Bill Ordemann, who will be retiring later in August. So this will be his first -- his last earnings call, and I fully intend to direct almost all questions to Bill.

Last quarter, we talked about what should drive investors back into energy stocks. And the conclusion was 'show me the cash', which we did. We continued to show the cash with a record $1.7 billion of DCF in the second quarter, which provided a record 1.8x coverage giving us $3.4 billion of DCF for the first 6 months of 2019. After increasing distributions for the 60th consecutive quarter, we retained $753 million of distributable cash in the second quarter and a total of $1.4 billion for the first half.

Adjusted EBITDA for the second quarter was $2.1 billion, that's up 18% in the same quarter a year ago for a total adjusted EBITDA of $4.1 billion for the first 6 months, which is up 17% compared to the first 6 months of last year. Our results continue to provide us healthy excess cash and the flexibility to fund our projects and maintain a solid balance sheet without having to issue equity.

Continuing the trend of previous quarters, Enterprise again reported a number of records during the quarter. In total, we reported 16 operational and financial records including record volumes in our liquid pipelines at 6.6 million barrels a day, our marine terminals of 2 million barrels per day, gross NGL fractionation volumes of 1.2 million barrels a day and natural gas pipeline volumes at 14 Bcf a day.

In our Petrochemical segment, our PDH plant exceeded design for the quarter. Yesterday, we announced that we had signed transport and terminalling service agreements with Chevron for crude transport from Midland to our ECHO terminal. We also announced that we entered into long-term agreements with Chevron for significant capacity on our SPOT offshore crude oil terminal, which enabled us to make a financial investment decision to build a terminal subject to government and regulatory approvals.

With access to over 6 million barrels a day of crude oil supply, and that's growing, more than 300 million barrels of storage, of which nearly 50 million is owned by Enterprise, the VLCC Terminal leverages our supply, storage and distribution network along the Gulf Coast. We believe this project provides a solution to U.S. producers who must have long-term certainty around their ability to competitively access international markets.

Earlier in July, we announced 3 expansions at our Houston Ship Channel marine terminal, which will enable us to increase loading capacity of LPG, propylene and crude oil. These expansions are on top of the LPG expansion expected online in the third quarter of this year. We already provide about 50% of the NGLs exported from the U.S. and roughly 1/3 of the crude oil and the lion share of propylene. I think we've shown by these expansion projects, we can and we will add capacity cheaper and faster than most others can build.

With integrated systems the size of ours, there are other fairly low-cost add-ons in our future. We completed construction and brought into service $900 million of major growth projects for the second quarter, including the third Orla gas plant and the Midland-to-ECHO 2 crude oil pipeline. We're on schedule to complete construction of $3.2 billion of major growth projects in the second half of this year, including 175,000 barrel per day expansion of our LPG marine terminal, the first phase of our ethylene export terminal, our isobutane dehydrogenation facility, a 10th NGL fractionation train, our Mentone I natural gas processing plant and a natural gas processing plant in East Texas.

We also continued to make progress in underwriting several additional organic projects, all of which will provide additional sources of cash flow.

We're focused on natural gas processing and NGL and crude oil takeaway and on defining what it means to be the U.S. petrochemical midstream provider.

I'd like to take a couple of minutes and speak specifically to the Houston Ship Channel. In the last 5 years, we've invested over $8 billion around the Ship Channel. People lose sight of the fact that in spite of our country's massive supply growth because of shale, U.S. -- and because of shale, U.S. demand for all liquid hydrocarbons, except ethane, has peaked. Even lower prices in U.S. has proved that you aren't going to stop that trend. Access to supply is the key to a viable export facility. And given our supply position in both NGLs and crude and our early focus on exports, we are a player in this area. Virtually every incremental barrel produced is headed for export. Thus, as we build pipelines and fractionators, you can expect export expansions from Enterprise.

We project that the U.S. crude oil exports will increase from approximately 3 million barrels a day today to more than 8 million barrels a day in the next few years as production from shale continues to climb.

Looking at supplies coming into our NGL system. Our internal forecast shows that our own LPG dock capacity will roughly have to double over the next few years. Add to that, our forecast for exports of petrochemicals and the refined products and the growth we see in Aframax crude oil exports to supply the Atlantic Basin even after we get our pending VLCC terminal built and our Houston Ship Channel terminal must continue to expand. On a more global scale, as U.S. production has grown, the U.S. producer has provided essentially all the incremental liquid hydrocarbons to the world. In many respects, the Houston Ship Channel is now just as important as Strait of Hormuz.

I haven't seen any ships have bombs put to their hull. I haven't seen any tanker ceased. I haven't heard Britain talking about consequences. The reason I haven't seen the price of oil skyrocket regardless of the tensions in the Middle East and around the Strait. The reason is because of what's happening in the U.S. from a production perspective because we have this important waterway, the Houston Ship Channel.

Approximately 90% of cargo traffic on this ship channel carries energy and petrochemicals. Neither this country nor the world has ever fully understood or appreciated the importance of the [Houston Ship Channel] (corrected by company after the call), but the U.S. oil and gas and petrochemical industry is beginning to.

Most major producers are pointing their hydrocarbons toward the ship channel, and the Houston Ship Channel is already the largest exporter of LPG to the world. The coalition of major producers, midstream companies and terminal operators recently joined forces to make sure that 2-way traffic will always be maintained in the ship channel. We were successful and have now joined the port and moved our Houston Ship Channel efforts to Washington for the funding and permitting of a significant expansion of the ship channel in an expedited way.

As we see it, every bit of the U.S. incremental energy growth is headed for export and most of that growth is pointed toward Houston. Houston is the energy capital of the world. We have oil, we have natural gas, we have natural gas liquids, we have refining, we have petrochemicals, we have pipelines, we have tank and salt dome storage, we have fractionation, we have docks and last, but not least, we have the Houston Ship Channel. Over the next few months, you can expect to see a heightened awareness on the importance of this waterway, not just to Texas and the U.S., but to the world. Hopefully, judging by our performance and recent announcements, it is clear that we remain focused on serving growing supplies and on developing markets, domestically and internationally for U.S. hydrocarbons and petrochemicals. That doesn't come without a long-term vision and that doesn't come without unbelievable execution by our employees. Randy?

Okay. Thank you, Jim, and good morning, everyone. I'd like to start off with the income statement for the quarter. Net income attributable to limited partners for the second quarter of 2019 was $1.2 billion or $0.55 per unit on a fully diluted basis, which included $13 million or less than $0.01 per unit in noncash mark-to-market hedging losses. This represents a 22% increase in earnings per unit excluding these noncash mark-to-market hedging activities versus the second quarter of 2018.

Cash flow from operations was $2 billion for the second quarter of 2019, a 38% increase when compared to the second quarter of 2018. In the second quarter of '19, cash flow from operations included $228 million of benefits from changes in operating accounts. In terms of cash flow from operations, our cash distribution payout ratio was approximately 47% for the second quarter of '19 and 58% with respect to the trailing 12 months ended June 30, 2019. And looking at the trailing 12 months, if you would, is a way to come in and remove the noise of cash uses and provided by seasonal working capital uses.

Free cash flow was $2.2 billion for the trailing 12 months of June 30, 2019, which represents a 96% increase when compared to the 12 months ending June 30, 2018.

In terms of capital investments and to follow what Jim said regarding capital investments, we have a total of approximately $6 billion of major capital projects under construction. And this includes the $3.2 billion, which he mentioned is expected to be placed in service by the end of this year.

Our capital investments in the second quarter were $1.1 billion, including $80 million of sustaining CapEx. We still expect growth capital investments for 2019 to be approximately $4 billion and $350 million for sustaining CapEx.

As noted in one of the other -- in the other press release that we issued this morning, we received contributions of $441 million today from Altus Midstream related to their exercise to acquire -- exercise of their option to acquire a 33% interest in our subsidiary that owns the Shin Oak NGL pipeline. We expect to receive another $57 million from Altus later in 2019 for their share of future CapEx to complete Shin Oak. In total, for the full year of 2019, we expect these contributions from noncontrolling partners or JV partners to be a total of $635 million.

So when you take that $635 million, apply it to gross -- growth CapEx of $4 billion, if you would, our net growth CapEx is somewhere between $3.3 billion and $3.4 billion is what we currently expect.

On June 24, we elected to go to the debt capital markets early to stay ahead of our debt financing and refinancing needs. We priced $2.5 billion of senior unsecured notes, comprised of $1.25 billion of 30-year notes at a 4.2% coupon and $1.25 billion of 10-year notes at a 3.125% coupon. The transaction was completed on July 8. We were very pleased with the level of demand for both tranches and are thankful for the continued support of our fixed income investors.

As of June 30, 2019, our total debt principal outstanding was $27 billion. Assuming the first call date for our hybrids, the average life of our debt portfolio was 13.8 years. Assuming the maturity date of the hybrids, that average life of the debt portfolio is 18.3 years. The average cost of our debt portfolio was 4.5%.

Adjusted EBITDA for the trailing 12 months ended June 30, 2019, was $7.8 billion, and our consolidated leverage ratio was 3.3x after adjusting debt for the partial equity treatment for the hybrid debt securities and also reduced for unrestricted cash.

Our consolidated liquidity was $4.7 billion at June 30, 2019, which included available borrowing capacity under our credit facilities and unrestricted cash. As of today, that same number for liquidity was approximately $7.9 billion, I repeat, $7.9 billion, which includes the proceeds from the debt offering and the aforementioned proceeds that we received today from Altus Midstream.

Moving on to equity issuances and repurchases. Enterprise received approximately $40 million of net proceeds from the dividend reinvestment plan and employee unit purchase programs during the second quarter of 2019. Beginning with the August 13 distribution payment, we elected to change the source of the funding of the DRIP and the employee unit purchase plan to open market purchases instead of newly issued units, and we'll continue this until further notice and as we do not currently need any external equity financing.

During the quarter, we also bought back or repurchased 1.1 million units of buyback activity. These purchases were done at an average weighted price of $27.95. So if you would, that equates to about an 11% distributable cash flow yield. We will continue to utilize the buyback program on an opportunistic basis going forward, balancing it along with our CapEx needs and distribution payment.

And with that, Randy, I think we can open it up for questions.

Thank you, Randy. Jason, we're ready now to take questions from our listeners. (Operator Instructions) Go ahead, Jason.

(Operator Instructions) Your first question comes from the line of Shneur Gershuni from UBS.

Maybe we can start off with a big picture question here. There's been a lot of volatility in NGL prices over the past couple of months. I was wondering if there are multiple opportunities for Enterprise to benefit from the situation via storage and frac later. In that context, can we also talk about due to propane export expansions that you're bringing online, does that close the international spreads? Are there going to be more opportunities there? And if we can even talk about ethane as well also given how low ethane is? Are there opportunities to take advantage of that? Are there things that you're noodling and thinking about that weren't discussed at the Analyst Day?

Justin, do you want to take that?

Yes. I mean, let's start with the export arb. I mean I think with our expansions that we've announced, the one coming on this year and the expansions announced between us and the rest of the folks in the market over the next 12 months, I mean I do expect that, that arb will start normalizing again. I think if it doesn't, that just supports further expansions that Jim's alluded to in the form of projects along the channel. I do think that NGL price dynamics today are supporting a lot of the various optimization opportunities that we have within our system when it comes to storage and regional arbs. So I think on a holistic basis that this NGL price environment benefits us in our assets in many different ways.

I'll just -- this is Brent. I'll just add that, question about storage, I think regardless of the hydrocarbon, storage by the water matters. You're about to see things in different markets where storage does matter. So I think we'll have opportunities from crude oil and petrochemicals and NGLs to capitalize on that.

And Shneur, this is Randy. One thing I would also add, just if you go back and look over time, it seemed like, any time we've seen processing margins get abnormally weak, if you would, there's a natural hedge out there with contango opportunities, and we're sort of seeing that again this time too.

That makes great sense. And just one follow-up question. With the projects that you just recently announced, how much will you be expanding capacity from Midland-to-ECHO? And are there any thoughts on bringing in a partner into the VLCC loader facility? Or do you want to own that 100%?

It depends on how many contracts we get as to whether I want to own it 100%. But yes, we -- I guess we have always entertained joint venture partners. We've got to get this thing permitted first. And that's off a good year plus.

Yes, I'd probably have the permit in its final stages by the end of first quarter next year with approval in the second quarter.

And just with respect to the Midland-to-ECHO side, how much capacity were you planning to add there?

Stay tuned.

Yes, I think that's stay tuned.

Your next question comes from the line of Jeremy Tonet from JPMorgan.

Maybe just picking up on the last point here. With the new agreements that you talked about the Chevron supporting the expansion of your crude oil system, do you envision kind of new pipeline, like a third Midland-to-ECHO? Or is this expanding existing capacity? Or is there any other kind of details that you could provide as far as what extensions you're envisioning here?

I think the only detail we're prepared to provide is we're building a pipeline.

A new pipeline. Okay. That's helpful. And it seems like you guys keep setting new records financially and have quite a strong position here. And just wondering if you could update us as far as your thoughts with regards to excess capital via deploying it on new growth CapEx or maybe accelerating your repurchase program or maybe picking up distribution growth a little bit higher towards where some of the peers are. Just wondering how you think about the interplay of those 3 at this point?

Yes, Jeremy, this is Randy. I think where we are is, again, we've got a number of growth capital expenditure opportunities that we like to get a little bit better visibility on those that are -- if you would, that are still underdevelopment. We think we'll get better visibility between now and the end of the year. And if you would, sort of 2019 was also the second year of a transition period. So I think the guidance that we provided for distribution growth in January, we're looking to stick to that. And we're -- we'll take a look at it at the end of the year, beginning of next year and sort of provide an updated guidance at that point. The buyback, we're still thinking about it in terms of opportunistic. And so we'll see what the market gives us on that front. While -- and I hear what you say on a number of our peers increasing their distributions lately, but also some of those guys, I think, were on that list that cut them pretty dramatically here a couple of years ago. So we're staying our course, and we're looking to return capital back to our partners. We've done that for growing distributions for 21 years. So I look to continue.

Your next question comes from the line of Michael Blum from Wells Fargo.

First question, just -- there's been -- I guess there's been some market conversations around a lot of I guess new entrants or participants trying to get into the LPG export market. I'm just wondering if you could just kind of walk us through your view of the competitive landscape as you see it here today.

Michael, this is Jim. I don't look at it that we have to compete with anyone. I'll look at it that they got to compete with us and they better be prepared to compete with a very aggressive fee program from Enterprise.

Got it. Okay. And then second question. The press release talks about, particularly with your Mont Belvieu fractionators, you saw higher volumes, but the press release mentioned lower fees. And I just was hoping you could just talk a little bit about the dynamics there. I would have thought with the frac market pretty tight that the fees would be pretty high as well. So I'm just -- just want to understand a little better what's going on there.

Yes. Michael, this is Randy. I think some of that could be lower margins from blending opportunities that we may have seen during the quarter.

Okay. But in terms of just the trends and fees for fractionation, would you say that, that's steady, rising, falling?

This is Zach. So I think some of that was some onetime events. We did have a turnaround in South Texas. But as far as fees, no, I think short-term fees are still elevated. They're above newbuild. When I say that, I mean short-term deals. I think long-term deals are still around. Fees are needed for newbuild economics. I think there's still an appetite from the producing community for more fractionation space.

Your next question comes from the line of Tristan Richardson from SunTrust.

To go back to the Midland-to-ECHO side, you guys have talked in the past about your optionality you have with Midland-to-ECHO 2 and the potential to return to NGL service longer term. With the commercial agreements announced last night and third-party crude capacity currently in line fill, can you talk about that optionality and potentially the timing there, particularly once Shin Oak goes into full service?

Yes, we always had the option -- we think it's a pretty valuable option that we have with Seminole. Secrest seems to think we're going to flip it in and out every other month, but we're not. But it is a valuable option that we have as Shin Oak fills up. It gives us an opportunity to either put that back in NGL service and add capacity to our crude pipelines. There's really no timing other than what opportunity presents itself.

Helpful. And then just last one. With the large slate of projects coming online this year, can you talk about just normalized levels of capital deployment? And just given the projects in the portfolio slated for 2020 and beyond, could we see capital deployment over the next couple of years closely resemble to the levels you're expecting here in 2019?

Yes, Tristan, when we come in, based on the projects currently sanctioned, and if you would, just for clarity, that doesn't -- that at this point does not include SPOT because that's still pending government approval. So if you would, just on the projects that have been sanctioned, we're looking at growth CapEx next year, call it, in the $2 billion to $2.5 billion range.

Your next question comes from the line of Jean Ann Salisbury from Bernstein.

Congratulations on the FID of the offshore terminal. Assuming that, that goes forward, I think we can assume that some of your existing crude export docks could be converted to NGL exports. Could we get a sense of how much of a time and cost advantage it is to convert rather than start from scratch? My understanding is that it's not a huge advantage because most of the cost is refrigeration, but I am happy to be corrected.

Graham, you got any thoughts on that?

Sure. I'm not sure I fully understood the question.

What's the cost advantage of expanding versus building new and Jean Ann seems to think that there's not a great advantage to it. You take a shot and then I'll take a shot.

If you take -- if you take crude oil off the dock, convert it to an NGL service, it's relatively quick and inexpensive to do that. That's not a big undertaking.

What about -- but she's referring to refrigeration.

Refrigeration, with the -- one of the things that we have at the docks, it allows us to expand refrigeration pretty readily is all of the other infrastructure, the piping, the insulated -- some of the things that we do for refrigerated loading are already there. So expansions to the facilities are relatively inexpensive.

That's helpful. And just as a follow-up, the original LPG exports that you signed a few years ago at the good rates. Can you remind us of the cadence of how those roll off over the next few years?

I didn't get the question.

LPG export roll-off contracts we're talking...

Let me take that one. Because I think we get so focused on, oh, do you have that particular part of your value chain fully contracted. Our LPG -- our fractionators are fully, fully, fully contracted. I believe that every incremental barrels got to go across the export dock, and as far as I'm concerned, from a value chain perspective, I'm fully contracted, whether I have 10-year contracts specific to the dock or not. So you heard us say, and to Michael's question earlier, is we're looking at the total value chain. And we're going to compete to the extent we have to on our LPG export because it's supporting so much other stuff that we have. So if you're going to compete with us on LPG exports, you better be able to do it with something like a 5 to 6 handle. Otherwise, you're not going to be there. Does that help you Jean Ann?

Your next question comes from the line of Christine Cho from Barclays.

I wanted to start on the NGL business. In the Permian, we've seen maximum ethane extraction there because no one wants to reject gas in a negative Waha pricing environment. With the upcoming in service of Gulf Coast Express that local pricing should improve and maybe rejection math makes sense. Am I thinking about that correctly? Should we expect that to impact NGL volumes out of your Permian pipes and the services downstream of that?

This is Brad. In the short term, you're going to see some frac spread compression on ethane. But again, going towards our value chain, we give our producers the ability to reduce their ethane recovery, but our value chain allows us to continue to produce that ethane. So as far as we look at it in the short term, I think we're probably not going to see a lot of swing in our NGL production out of the Permian.

Okay. And then, Randy, you mentioned that there's good growth opportunities, and you're waiting for clarity before looking at what you want to do with excess cash flow. How do you think about M&A just given that your balance sheet is one of the strongest in this space and there are various parties looking to exit their midstream position?

Christine, I mean we, I'd say, continually get shown "M&A opportunities", and where we keep coming back is our organic growth projects that bolt-on to our existing system give us better returns on capital. And I daresay when we come in and look at some of the M&A opportunities that are provided, the capital intensity to drive DCF per unit growth is much less with organic growth projects than it is with M&A opportunities. So that continues to be our focus. We'll continue to come in and look at opportunities. But really, we're more focused on the growth CapEx and just develop it organically.

Your next question comes from the line of Justin Jenkins from Raymond James.

I guess maybe just to start real quick as a follow-up on Midland-to-ECHO 2, the extra materials noted, it did about 209,000 barrels a day of throughput in the quarter. Is that pretty close to max capacity? Or can you squeeze a little more out of that?

We could probably squeeze a little more out of it, but it would be at a high cost.

Fair enough. And I guess second question here more on the octane market? It seems like that's been an area of strength here recently and based on what we're seeing on the refining land, looks like that's going to continue for some time. I know we've got iBDH later this year. But anything else in the cards in terms of capitalizing on maybe more octane enhancement opportunities into 2020 and beyond?

Not really. I mean we're realizing some nice earnings from our BEF plant, and you have quite a bit of demand for the isobutylene mix that will not be -- that we have available too.

Your next question comes from the line of Pearce Hammond from Simmons Energy.

My first pertains to the SPOT terminal. It was very helpful color you provided on your expectation of when permitting will occur. But how long would it take you to build the actual terminal?

Graham?

We're looking -- we're basically looking at a couple of years.

And that would be a couple of years from when you get all the permits in place? Or would that be happening ahead of the permits?

Some of that would be happening ahead of the permits.

Perfect. And then the follow-up question. In your prepared remarks, you talked a little bit about the Houston Ship Channel and its importance to the nation and to the energy industry writ large. If you could elaborate a little bit more, are you seeking to get more support in Washington to do anything specific within the ship channel, whether it would be dredging or any kind of other economic support? Or is it just more to shine a light on the importance of the asset?

I think there's an initiative that industry is working with the Port of Houston on to widen the [Houston Ship Channel] (corrected by company after the call) from 530 feet to 700 feet up to Morgan's point and then to do some dredging, making it deeper at the upper end of the ship channel. What that does for us is it gives us more daylight hours, in particular, for LPG. So if we gain 3 or 4 daylight hours each day, that's pretty dramatic for Enterprise and others. Bob, you want to add to that?

Yes, so the port has been working with the Army Corps of Engineers for 4 years on a plan to widen the ship channel. That plan should come out early spring next year to get voted on by the federal government to approve the project, so that we can move forward to widening it to 700 feet. And industry is working with the port on trying to accelerate the construction of that project...

Through local funding.

Through local funding.

Your next question comes from the line of Colton Bean from Tudor, Pickering, Holt.

So just to start off on the propylene side of things, it looks like you had a pretty good quarter of volumes there. I think you noted that the PDH unit was running at 120% of nameplate. So just how do you view the sustainability of that rate? And does it impact what you need to underwrite to feel comfortable with the potential PDH unit addition there?

I don't think we -- if we said 120%, I missed it. Did we? We ran at 120%?

If you get the accounting on byproducts or not, I think the actual propylene production was more like 106% of nameplate.

Okay. Okay.

And I think we would expect that to be at those levels going forward.

And then just in terms -- in terms of the second part of your question, we're still commercializing and having negotiations with our customers on PDH 2.

Got it. Okay. And so not necessarily a read-through from these results into any sort of change in goalposts around that?

Correct.

And then just on the nat gas side of things, it looks like the marketing margin was even in context of a nearly 250 spread for Waha, it looks nat gas margin was pretty impressive there. Did you guys realize any incremental spot volumes kind of on a quarter-over-quarter basis?

But I don't know how much it is. Do you have it, Tony?

Yes, part of it is we -- the expansion that we did to be able to come in and transport more natural gas from Waha to the Gulf Coast and the Carthage area, that really didn't go into effect really until late third quarter of last year. So yes, we had more opportunities in the second quarter of '19 than we did in '18.

Got it. Okay. But not necessarily any change year-to-date?

No.

Your next question comes from the line of Spiro Dounis from Crédit Suisse.

Starting off on crude exports. Jim, very encouraging to hear your outlook there on 8 million barrels a day of exports in the next few years. But I guess in the near term here, I think we continue to hear maybe concerns from the investor community just around all the crude that's going to be ending up on the Gulf Coast pretty soon as all of these Permian takeaway pipes come online, specifically kind of south of Houston. Just curious how you think about how the industry solves for that without sort of a big price dislocation in the meantime?

This is Tony. I'll start it out and then see if Brent wants to add anything to it. Clearly, we're piped to bring crude oil to the Gulf Coast. I think really Brent has already covered it. Once you get it to the Gulf Coast, it's -- it has to be -- it has to hit a terminal and then it has to hit a dock. That's kind of the end of story. And so terminal capacity and dock capacity is critical to the U.S. producer. It's that simple. It's going to go.

Brent, speak to your flexibility to load at our other terminals.

Yes, I mean so if you look at how Enterprise runs its crude docks, it's not a whole lot of different than when Zach talks about how we optimize around our fractionations. We have other terminals that we can flex on. So the goal is to load everything at the Enterprise 100% owned Houston Ship Channel. Then we kind of optimize around that based on other facilities. So we have a 50-50 JV with Enbridge at Freeport and Texas City. And then ultimately, we'll flex down to Texas City when we get backed up when things happen and things always happen. We're about to see that in different markets as more supply comes online. In terms of the demand, we're still seeing a healthy appetite for crude oil, the arb, the water is probably decreased slightly over the last month or so. But -- and we've said this before in NGLs, is these barrels were priced to clear. And there maybe some lumps along the way that may take some time to invest capital and make things happen. But if you spend any time in China and you spend any time in India, you are seeing the demand happening. And the amount of money that these guys are investing to take what we produce, that is real. It will take time, but it is real.

Okay. So just to clarify, it sounds like you're saying that in the near term here in terms of our ability to export, it's pretty balanced with all the new pipeline capacity and supply that's coming online. Is that fair?

I think it's fair. But I mean we've been public on this. I mean pipeline capacity is one thing, dock capacity is another thing, storage is another thing. And to think that all these things are going to hum at max capacity, I think, is a false thought.

Yes, that's fair. Second question is on the Permian, Delaware maybe specifically. Peers out this morning with pretty severe cuts to the outlook pointed to things like well timing, power issues, weather issues. Just curious if you guys had seen any of that in your acreage?

No, the answer is no.

This is Brad. I would say most of our customers, large integrated producers have done a real good job of laying the groundwork for production growth. So as of right now, our volume curve is kind of where we thought it was going to be, hadn't seen a lot of slowdown.

Your next question comes from the line of Keith Stanley from Wolfe Research.

Just on the capital backlog in the slides, 2020 and beyond is about $1.3 billion. So I'm assuming some of that's the Midland-to-ECHO expansion. But just any more detail breakdown on where that $1.3 billion increase is coming from?

Some of it was also -- Keith, this is Randy. Some of it was also on the LPG and crude and propylene export expansion projects that we mentioned. We also have -- we also announced during the quarter some new propylene and ethylene pipelines as well as an expansion of Aegis. And your math was right at $1.3 billion.

Your next question comes from the line of Michael Lapides from Goldman Sachs.

Just thinking about SPOT for a second. Can you talk about kind of a range of how capital intensive or kind of a CapEx expected if you get the go-ahead from Uncle Sam to move forward?

It's not cheap.

Is there just kind of a back of the envelope, a rule of thumb to think about it in terms of size and scale? And also trying to think about the EBITDA impact, kind of how impactful relative to the size and scale of Enterprise?

Yes, I don't think it's impactful relative to size and scale of Enterprise. And I'm going to narrow it, not very narrow, but I'll give you an answer of more than 1, less than 2.

There are no further questions at this time. I turn the call back to Randy Burkhalter.

Thank you, Jason. And with that, we're ready to conclude our call today. I'd like to thank everybody for participating. And Jason, if you would, could you give our listeners the replay information. And then after that, we'll conclude the call. Thank you.

Absolutely, a digitalized replay of the discussion will be available beginning today, July 31, 2019, at 1 p.m. Eastern and will end on Wednesday, August 7, 2019, at 11:59 p.m. Eastern Time. To access the digitalized replay, please dial (855) 859-2056 or (404) 537-3406. That concludes today's conference call. You may now disconnect.

Thank you.