Enterprise Products Partners LP (EPD) 2018 Q3 法說會逐字稿

Good morning, and welcome to the Enterprise Products earnings call. All lines have been placed on mute to prevent any background noise. (Operator Instructions)

It is now my pleasure to hand the conference over to Mr. Randy Burkhalter.

Thank you, Nicole. Good morning, everyone, and welcome to the Enterprise Products Partners third quarter earnings call. 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 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 we jump into the third quarter, Randy Fowler and I wanted to take a step back in time. A lot of you may not realize, but the third quarter of 2018 marked our 20th anniversary as a public company. This year, we're on track for our 20th consecutive year of increasing our cash distributions to partners, and, to our knowledge, no other U.S. midstream company has accomplished that.

A $1,000 investment in Enterprise at the IPO, with reinvested distributions, would be worth approximately $17,000 today. We've accomplished this through 2 commodity price cycles, a petrochemical cycle, and 1 of the worst financial crises in U.S. history. We are proud of these accomplishments and our team of 7,000 employees that drive this performance, and we're thankful to our long-term debt and equity investors and to our customers, who make this performance possible.

It's been a quick 20 years, don't you think, Randy?

It has.

Now on to our results. Supported by a robust supply growth and strong demand, both domestic and global, our businesses continued to perform exceptionally well in the third quarter. Gross operating margin, excluding non-cash mark-to-market, was $1.9 billion, a $576 million increase versus third quarter of last year.

These increases are largely attributed to a combination of new assets put in service, volume growth and operational leverage associated with our legacy assets, and increases in gas processing margins. Long-term fundamentals are strong across our entire value chain, and we're working hard to make this kind of performance the norm.

Our results provided distributable cash flow of $1.6 billion, which provided 1.7x coverage. Our DCF for the first 9 months of 2018 was $4.4 billion, providing 1.6x coverage and $1.6 billion of retained distributable cash flow. This kind of performance for the quarter and year-to-date puts us far ahead of our self-funding goals we communicated in the fourth quarter of last year.

Moving to our operating results, increased volumes and margins across all our businesses led to 16 operational and financial records for the third quarter, building on the 14 from last quarter. Our NGL and natural gas business segments reported 7 operational records relative to volumes for our pipelines, marine terminals, fractionation and fee-based processing, and our crude oil and propylene businesses reported near-record volumes. We also set 9 new financial records in the third quarter, which was covered in our press release.

Total capital spending for the first 9 months of this year was approximately $3.3 billion. We expect to spend $4.2 billion in 2018 and about $350 million in sustaining capital.

The current environment of strong demand for our services, coupled with productive discussions with customers to develop new infrastructure projects across all of our business segments, is the strongest climate we have seen in recent memory.

We announced 2 additional projects this morning, a 150,000-barrel-a-day expansion of our NGL fractionation capacity at Mont Belvieu and our Mentone natural gas processing plant serving the Permian. Including these projects, we currently have over $6.6 billion of growth capital projects under construction that are scheduled to be completed and generating new sources of cash between now and 2020.

In addition to what we have announced and have under construction, we have other exciting and strategic projects under development. I'll give you a couple of examples. Our deepwater port project is advancing on both the engineering and commercial fronts. We're in discussions with domestic producers and global consumers.

As I look at a lot of announcements and hear a lot of talk, one must realize that anyone can build a terminal, but it's what's behind that terminal that determines its success. The reason we are the largest ethane and propane exporter in the world is because of the 130 million barrels of NGL storage, and over 1 million barrels of fractionation that we have at Mont Belvieu, and our pipeline connectivity bringing Y-grade from the Eagle Ford, from the Permian, from the Rockies and the Mid-Continent. We call that supply aggregation.

The same is true with crude oil. A terminal's success depends on what's behind that terminal. Enterprise is -- can aggregate 5 million barrels a day of crude oil today, and that will grow to 8 million barrels a day over the next 5 years. That's accomplished because we have pipelines of our own bringing crude from Cushing, which can access the DJ as well as Canada, from the Permian, and from the Eagle Ford, and we -- our header system is tied to other third-party pipelines.

Our terminal has connectivity to 300 million barrels of storage and access to almost 40 different grades of crude oil. An efficient market hub requires supply, demand and connectivity. Enterprise's connectivity to its own and third-party pipelines and storage gives it unparalleled crude oil supply aggregation. I don't think there's another location that has that.

And finally, the launch next Monday of the CME Gulf Coast crude contract at Enterprise Houston locations will give our terminal price transparency, which will be a huge benefit to our terminal customers.

Another example -- we are finalizing engineering and licensing arrangements for a second PDH. And frankly, it's not out of the question that we could build 2, as negotiations are under way with several petrochemical companies. Again, couple our feedstock position -- read that to be supply aggregation of NGLs. Couple that position with our growing petrochemical infrastructure, and we are well on our way to significantly extending the Enterprise value chain into primary petrochemicals, which adds significant long-term global GDP upside to Enterprise.

Last, but not least, one should not assume that Enterprise is done building pipe out of the Permian. We continue to believe that the Permian has substantial upside, and we have an excellent footprint for expansion and extension. As we said in the press release, our goal is to position Enterprise to capitalize on these type of opportunities while self-funding our equity needs to drive continued growth in DCF per unit and, ultimately, the value of our units.

These results are impressive, and we're obviously proud of them, but they're not luck. Our highly integrated systems across the entire value chain, from producing regions to end users and now with emphasis on growing international demand, give us tremendous operating leverage across our businesses, plus long-term growth opportunities in virtually all environments.

I believe the last few years have proven that when the industry goes through a slump, our investors can take comfort that our integrated asset model and our dedicated employees are going to provide superior coverage and always allow us to grow. Then when fundamentals strengthen, like today, those businesses are going to provide even greater coverage. Our goal is to perform in any environment and not to dilute your investment.

I'll finish today reminding you that what you own when you own Enterprise -- first, you own what I think is the best supply system in the U.S. for oil, gas, NGLs and petrochemicals. Next, you own the most integrated demand system in the U.S. And finally, when you own Enterprise, it's our goal that you will own the best liquids hydrocarbon export system in the U.S.

And with that, I'll turn it over to Randy.

Thank you, Jim. Good morning, everyone. I'd like to start with a few items on the income statement and cash flow statement. Net income attributable to limited partners for the third quarter of 2018 was $1.3 billion, or $0.60 per unit on a fully diluted basis. This compares to $611 million, or $0.28 per unit on a fully diluted basis, for the same quarter in 2017.

We recognized a total of $204 million, or $0.09 per unit, in non-cash mark-to-market gains during the third quarter of 2018, primarily to Midland to Houston basis hedges on crude oil. Adjusted earnings per unit of $0.51 per unit for the third quarter of this year is a 76% increase compared to the same adjusted number for the third quarter last year.

Distributable cash flow per unit, excluding non-recurring items, for the third quarter of 2018 increased 45% to $0.71 compared to the third quarter of last year. And as Jim mentioned, we retained $632 million in excess distributable cash flow in the quarter and had distribution coverage of 1.7x.

To put in context our strength to generate distributable cash flow per unit in the current business environment, for the first 9 months of 2018, our distributable cash flow per unit, excluding non-recurring items, was $2.00 per unit. This compares to our record DCF per unit of $2.06 for all of 2014. Through the first 9 months of 2018, we are about 30% ahead of 2014's record pace.

Moving to capitalization and our balance sheet, at September 30, our total debt principle was $26 billion. Assuming the first call date for our hybrids, the average life of our debt portfolio was 13.4 years. Our effective average cost of debt was 4.5%. And 89% of our debt portfolio was fixed as of September 30.

On October 3, we priced an aggregate $3 billion of senior unsecured notes, comprised of $1.25 billion of 30-year notes at a 4.8% coupon, $1 billion of 10-year notes at 4.15%, and $750 million of 3-year notes at 3.5%. Based on our debt maturities in 2019 and our current estimate of at least $3.5 billion in growth CapEx in 2019, coupled with strong support from our fixed income investors, we elected to upsize the offering to $3 billion. Absent an acquisition, we do not currently expect to have the need to be back in the debt capital markets until 2020.

Adjusted EBITDA for the 12 months ended September 30, 2018, was $6.9 billion, and our consolidated leverage ratio was 3.6x after adjusting debt for the partial equity credit of the hybrid debt securities by the rating agencies and further reduced by unrestricted cash.

Our consolidated liquidity was approximately $3.3 billion at September 30, which included available borrowing capacity under our credit facilities and unrestricted cash. The proceeds from the October debt offering obviously increases that liquidity. As of yesterday, total liquidity was approximately $6.5 billion.

Moving on to equity issuances, during the third quarter, our only proceeds were from the distribution reinvestment program and employee unit purchase program for approximately $188 million, which included $106 million from privately-held affiliates of EPCO.

Aside from the DRIP and employee purchase plans, we have not raised any equity in the past 15 months. Given our current business and cash flow outlook, we elected to reduce the discount under the dividend reinvestment plan to 0, effective with the distribution expected to be paid in February 2019.

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

Okay, Nicole, we're ready to take questions from our participants.

(Operator Instructions) Your first question comes from the line of Jeremy Tonet with JP Morgan.

Good morning. Congratulations on the quarter.

Thank you, Jeremy.

I just wanted to touch on the fractionation market, and it seems like industry reports would point to that being extremely tight right now and a lot of logistical challenges as far as more NGLs hitting Belvieu than there's frac space and that causing issues with storage, and then also the petchem pull being so strong. It seems like that tightness is likely to persist until 2020 if -- as long as Brent and Henry Hub kind of stay at these spreads. And so I'm just wondering what are your thoughts on I guess how tight the market is, what's the duration of that tightness, and how does that impact Enterprise.

Jeremy, I think you just nailed it. I think 2019 is going to -- at the rate things are going right now, it's going to be very tight. Pipeline capacity is tight right now. That gets relieved whenever, frankly, Shin Oak comes on. But fractionation we think will be tight through 2019. Our position is we have not -- we're not in a situation where we have over-contracted our capabilities. We are having people come to us and ask for fractionation capacity, and we're looking at the levers that we can pull to accommodate them, and, frankly, we'd like to tie those opportunities to longer-term deals.

That makes sense. That kind of goes into my next question with Shin Oak there, and I just wanted to touch on progress and thoughts, I guess, when Shin Oak comes online as far as converting some of the other NGL pipes that you might have excess capacity into crude oil service given kind of a good need for that pipe, incremental crude oil takeaway out of the Permian today.

Well, you heard in my earnings -- in my script that I said we're not through building takeaway out of the Permian, and we are putting ourselves in a position to be able to convert a pipeline, but the earliest that would be would be when Shin Oak comes on, and that's not until the second quarter of next year.

So a conversion middle of next year for the NGL into crude pipes? Is that possible, or how much of a lag time would there be?

We're putting ourselves in a position to convert an NGL pipeline to crude oil service, and the earliest that would be would be when Shin Oak comes on. Now, Jeremy, you can ask the question again. You're going to get the same answer.

Fair enough. I didn't know if you'd comment on the lag time. Last 1 for me. I mean, you guys have been on the DRIP. You're decreasing the discount to 0, but based on the numbers we see, it seems like it might make sense to go the other way and repurchase units. Under what conditions would it make sense for Enterprise to start buying back units? Granted, you guys have a very deep organic growth portfolio, but it seems like fundamentals are really coming your way and you're going to be gushing a lot of cash flow.

Jeremy, for one, when we sort of went with the equity self-funding goal, at the time, we were talking about $2.5 billion to $3 billion in growth CapEx. Now we're running, call it, between $3.5 billion and $4 billion a year of growth CapEx. So I think we've got good places to put the capital back to work with some good returns on capital. I think the other overlay, that you come in and you look at it from a buyback standpoint. When you do a buyback, by definition, you're reducing your financial flexibility, and given the equity markets that we're in, where we're not seeing any funds flow at all come into the midstream space -- doesn't matter if you're a C corp or an MLP, I think this is a -- we're at a time or in a season where you need to make sure you've got financial strength and financial flexibility, so I don't see a buyback in the near term.

Your next question comes from Shneur Gershuni with UBS.

Just a couple of philosophical questions. First, touching on the NGL market, as you responded just a few minutes ago about how tight it is and so forth, I was wondering if you can sort of talk about contract negotiations in general. Are we in an environment where as you build the next suite of assets, does it lend itself to longer-duration contracts and better pricing terms than you had previously? Or I guess said differently, are we in an environment that the next dollar of CapEx deployed results in even higher returns versus the last dollar that you spent?

I hope so. I think we're in an environment where you can -- you probably are better off leveraging the opportunity into longer-term deals rather than trying to mine it for the last penny. Does that make sense, Shneur?

No, absolutely. I was just wondering if when you convert it into longer-term deals, is it better than longer-term deals that you've signed previously.

Yes.

Following up on that, in terms of your growth rate -- I mean, obviously, you've exhibited a very strong growth rate this year. When you moderated distribution growth in 2017, you talked about reevaluating it in 2019. Do you have any sense on where you think Enterprise's sustainable growth rate is now given kind of the performance that you've had this year and the visibility of growth outlook that you have going forward?

Shneur, it seems like it goes higher every week. Right now we're in the middle of our 2019 planning process, and to your question, growth CapEx is very fluid right now, and Jim mentioned we're trying to come in and underwrite 2 or 3 other projects in development. So what we -- the projects, if you would, that have been sanctioned right now I think puts us at about $3.5 billion of growth CapEx next year. That could grow and grow by a sizable amount, so I think we need to continue to monitor that. And what we had said is we'd come in and provide guidance on 2019 distribution when we report fourth quarter earnings, and I think as dynamic as things are right now, we'll adhere to that.

One of the things that as you look forward -- where we can grow has changed. We can grow in more areas. That PDH plant we built was a huge step down into the primary petrochemicals as it was iBDH. So not -- we're not just building pipelines anymore, or processing plants or fractionators. We're building primary petrochemical plants, which gives us even more opportunity.

I completely recognize it. When I do the back of the envelope math in terms of do you retain distributable cash flow, it seems like you can easily self-fund a $6-billion-a-year program, and I guess that's where the question is coming from.

I think Graham Bacon, that runs engineering operations, just turned white when you said $6 billion.

Fair enough. One last question. Randy, last quarter, you talked about Mr. Market. You've had a very strong quarter this quarter as well, too, but the stock price, outside of today, has been kind of lackluster. When I sort of think about all your financial metrics, you've got coverage, self-funding and so forth. You've done everything right. But have we hit a point, with almost $60 billion in market cap, that Enterprise has gotten too big for the MLP market? Does it make sense to review ticking the box or somehow entering the C corp market to make sure that valuation is properly reflected?

Yeah Shneur. I mean, that's something that we continue to evaluate. As we come in and look at valuations, I don't necessarily think it's MLP valuation specific. I think it's broader than that. Again, I think, if you would, energy is still macro. If you would, the energy sector is broadly out of favor, and we need to see some sector rotation back into energy broadly. And then I think midstreams will get our share of that capital, but if we come out and look at those guys that have converted to C corps and we look at the valuation of the large, diversified MLPs, although there aren't very many of us -- the valuations are on top of one another when you come in and you look at the peer group. So I don't know if checking the box necessarily results in higher valuation.

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

Have you had a material uptick in requests from external parties to store Y-grade? And if so, is that a fixed fee to external parties where you can kind of charge up to what the market is willing to pay, or is it a fixed fee where you can't really move that around?

Jean Ann, this is Brent Secrest. There's definitely more interest in storing Y-grade. I think there's some interesting in, obviously, fractionating that Y-grade. So, ultimately, it depends on the structure of the contract. In some cases, we're storing Y-grade. In some cases, it's a much larger fee to fractionate. But, overall, there's definitely demand for storing Y-grade.

And the storage for Y-grade, that fee can kind of move around based on how much demand there is for it?

That's right.

And I was just wondering, how many fracs do you have space to build in Mont Belvieu? How should we think about that limitation, if there is one?

We've got more space than I hope we build fracs. I joke sometimes with Randa Duncan that at the rate we're going, we're going to have them built all the way to Dayton, Texas. But we've got -- what have we got left, Graham, 1,500 acres, 1,300 acres out there?

Yes, we've got about 1,300 acres.

And how many acres does a frac take up? 5?

It's probably only 10, 20 acres.

Okay, call it 15 acres, Jean Ann, and do the math.

And then just one last one, kind of building on a question that was asked before. Is it fair to think that the new processing and frac announcements from today might really reduce the chances that you will convert the NGL line? It seems like you might need it in NGL pretty soon.

Well, Shin Oak is 550,000 barrels a day. Tug, can we expand that beyond -- where is Tug? Is that about it, 550?

Yes, about 550 is max.

So I think we have ample Y-grade space.

Your next question comes from the line of Tom Abrams with Morgan Stanley.

I'll follow up on that NGL to crude line conversion as well. You're setting yourself up to do that possibly next year. Would it be a fairly rapid conversion, or would it take 9 months, say, to do?

I'll say the same answer. It won't come up, Tom, before Shin Oak comes up.

Well, once it does, once Shin Oaks comes up, is it almost an instant conversion, or is there some work that needs to be done?

Oh, it's going to come up when -- it would come up, at its earliest, when Shin Oak comes up.

And then on the NGL side, there's just been a lot of volatility in ethane prices in the basins on some import/export differentials, Conway/Belvieu differentials against the business, I guess, if you will, from the third quarter to fourth. Is that a potential headwind of any magnitude quarter-to-quarter?

It's hard to say. I'm not convinced it is, because our pipelines have been on tug allocation throughout the third quarter, which probably created some of those spreads.

Well, I think, too, because you -- it looks like your NGL equity volumes, you kind of gave up some of those, which I assume had an economic impact in favor of your customers. You're managing that, to some degree.

Exactly. Some of our equity volumes are when our customers do not elect -- we have discretionary opportunities to process that gas ourselves, but the margins have been such that they've been electing full recoveries.

So, conceivably, the market would give you less, but your contracts -- your equity volumes would give you more. That's one way to think about it, correct?

Yes.

And on the taxpayer question -- or, I'm sorry, C corp question, when you do that math and look over it again and again and again, when do you think, if you did go C corp, you would be a taxpayer?

A little bit, it depends on how you wind up becoming a taxpayer and checking the box, C corp conversion step up. I don't foresee us coming in and doing any type of step up. That would not be in our plans because of the tax liability that would cause to limited partners out of the gate. I mean, we're profitable where we are. Tom, some of it gets down to do you do bonus depreciation, do you come in and take tax depreciation over time? There are a number of things that you can do to come in and manage that tax liability. So it's hard to commit right now what we might do if we're taxable as a C corp when we're still an MLP.

I understand. I'm just trying to get to the idea that it's not a layup that C corp is home free, that there's some future tax liability, whether it's 5 years, 10 years down the road, that has to be considered in this math.

Oh, sure. Yes, very much. Now, again, that's where you come back in with what Congress did in enacting bonus depreciation with where your growth CapEx is, and acquisitions for that matter. I mean, you can -- again, depending on what your growth profile is, you can keep your income taxes negligible for quite a while, just depending on what your growth rate is.

Last question is on this offshore loading facility, and you're working on engineering and customer relationships. Can you start the permitting without a fully defined project, or does that have to wait until you get that in hand and can define it to the regulators and that kind of starts the clock on that, call it, 18-month permitting process?

This is Graham Bacon. I think we have the project defined at this point well enough that we're proceeding with the permitting process, and we have all the blocks in place to proceed. We're just finalizing the package at this time.

Nicole, before we go to our next one, let's remind our participants if we could keep our questions to 1 question and 1 follow up, please, I would really -- that way, we can get to more questions. That'd really be great. Thank you. Go ahead.

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

I just wanted to start with a line you had in your release. You guys said that your equity NGL production volumes for the quarter were reduced to alleviate takeaway, pipeline capacity constraints. Can you go into what this means exactly? I wasn't sure if you were putting your equity NGLs into storage.

I think what we were talking about is that was the triggers and what have you. We're pulling levers to accommodate some of our customers, and some of the levers that we're pulling reduces our equity NGLs in order to create pipeline and frac space for opportunities we're getting from producers.

Okay, but if you're reducing your equity NGLs, isn't the customer still, I guess, increasing their NGL production to offset your reduced equity NGLs?

Yes. That's the point.

I see. Okay.

I think it's some of each.

And then I hate to beat a dead horse, but around another question for the C corp. How do you think about the UP-C structure versus going full C corp? There would be differences in corporate governance, board makeup, but you can't go into the big entities as an UP-C, so curious as to your thinking there.

Christine, we had our day in the sun when we had 4 different equity securities trading at one time, and I think we like simple is better, so coming in and having 2 equity securities outstanding does not have a lot of appeal to it.

Okay, but you could still have an UP-C and do 1 security.

But, I mean, again, if one of the goals of the UP-C is to get access to the capital markets through the UP-C, then you're looking at 2 publicly traded securities.

Your next question comes from the line of T.J. Schultz with RBC Capital Markets.

Just first a quick follow up on the offshore port. The advantages of supply aggregation makes sense, but as we see more announcements to develop these ports and now an onshore export option to handle VLCCs, does an onshore solution have any advantages as far as the permitting process may go? And then is there a need for more than one solution here?

The onshore process has its own challenges with dredge depths and maintenance and permits associated with that, so there's not a clear advantage there.

I guess for the second question, if we can just touch on the Eagle Ford. We've seen some ownership changes there. You had pointed, I think at the Analyst Day, to 50,000 to 100,000 barrels a day of incremental volumes this year. Are you seeing that, and what is the open capacity you have on that crude system? And then on Chesapeake's call yesterday, they talked about access to ECHO and to Corpus and excess capacity across 2 pipes. So in that case, what would drive more volumes to ECHO as opposed to Corpus across your systems?

What would drive more volumes to ECHO rather than Corpus is Corpus is a destination. Houston is a market. It has 4.5 million barrels a day of refining, 300 million barrels of storage, and access to water. Corpus will work until it doesn't work. Brent?

That's it. I mean, that's been our position from the beginning.

It's no different than NGLs. Producers typically want to go to the biggest sponge.

And if we see more activity in the Eagle Ford, what's kind of your open capacity you have on that system?

A lot.

We've got plenty. The Eagle Ford -- thank God for demand fees.

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

Jim, you mentioned ongoing conversations with off-takers there for the crude export terminal. Any additional color you could offer on that? And then just as you've been working through the feed study, have you guys been able to refine kind of a general construction timeline? I think the permitting process was highlighted to 18 to 24 months, but just thinking kind of post-permitting what the actual construction timeline might look like.

The color I can give you on the discussions is that Bob Sanders, Brent Secrest and I spent 11 days in Asia recently, and the fact I would spend 11 days with Brent Secrest in Asia says something about how serious we are. To the permitting, I thought it was 1 year. Graham?

Correct.

And then the timeline after that -- I mean, this isn't rocket science, is it?

No. It's something we're still defining. We're still defining that timeline.

I think, as Graham said, we're still defining that timeline, T.J.

And just on the Frac XI announcement, so it's slated to come on just behind Frac X and, arguably, a little bit sooner than market expectations there, so can you just give us a bit of commentary on the supply chain background that allowed you to hit that timeline?

One thing is Shin Oak. Another is the deal we recently did, that we announced, at Alpine High. That really starts ramping up in that timeline. So I think those are two of the biggies.

Another is the plant we announced this morning.

Yes, Mentone.

Maybe more specifically on the engineering and construction side, in terms of anything that you guys had already secured, maybe long lead-time items that factored into that?

Graham?

I didn't catch the question.

The timeline on the construction of Frac XI. Obviously, we've already done some long lead time equipment purchases.

Yes, we've got -- the long lead items are defined. All the engineering is complete on the long lead items, and it's in the purchasing queue moving forward.

If you think about it, it wasn't that long ago we had 3 trains out there, so we built a number of trains over the last few years, so really we've gotten pretty good at it.

Yes, we have. I think it's pretty -- that timeline is pretty well defined, and shop space is tight, but we've got a place in -- we've got our place in line.

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

You talked about strategic projects out there and positioning yourself for expansion and extension out of the Permian. I'm curious of the potential ramp here on Shin Oak with an additional 40-a-day potential on Mentone and Orla 3 and Alpine High. Is the 550 a day adequate enough initially to handle the supply growth you guys are seeing and potential for expansion there?

I think it's sufficient for the ramp we see. I hope it's not.

Your next question comes from the line of Matthew Phillips with Guggenheim.

Another export-related question, the recent NGL announcement on the ship channel. I mean, do you see that as sufficient for the runway you all are building out in terms of inbound NGLs, Shin Oak, et cetera, and frac capacity at Belvieu, or is this a precursor to needing more capacity 3, 4 years hence?

I think it's the latter. I think this expansion was relatively cheap and a pretty good bang for the dollar. If we look forward at some of Tony Chovanec's work with our fundamentals group, we have ways to further expand, and we probably will.

Contingent upon that, I mean, are you expecting to move some of the crude export volumes flowing through that hub offshore and that frees up space? And if, for whatever reason, the SPM project gets pushed out, I mean, does that change how you view the ship channel site?

First and foremost, yes, if we -- as we build the offshore port, we will backfill that capacity with more LPG export capability, which we think will be needed. If it takes longer than we think it will to build an offshore port, then we have a lot of capability in Texas City and in Beaumont.

For NGLs?

No, for crude. I'm sorry. NGLs is going to be on the ship channel. But my point to you was we can move crude to other ports to accommodate NGLs.

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

Jim, I just wanted to go back on a comment you made earlier just around this being one of the strongest markets you've seen in a while. So I guess the question is from an M&A perspective, what does this mean? Does the math start to really work, just given the increasingly positive outlook coming out of you guys, just against the equity values across the space?

Are you asking if we're looking at M&A?

Yes.

Yes, I guess we constantly look at it, but we find that building, organic growth gives us better returns than an M&A would, so it's much more accretive to build.

And then you also mentioned heading over to Asia, just in the context of crude exports. I'm curious just on the backdrop of the trade tensions and the Chinese kind of already curtailing crude exports out of the U.S. Do you see any risk there on that front, or is the view that effectively the crude gets displaced in one spot and it effectively goes to another?

Trade patterns change. It becomes less efficient, but volumes move.

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

Can you give an update on the status of the 100,000-barrel-a-day Seaway expansion and just the level of customer demand to maybe do a larger expansion at Seaway, if that's something you're actively working on still?

Thanks, Keith. This is Jay Bany. The DRA expansion was mechanically complete earlier this month, in October. We continue to work with our connected carrier to basically test out that, increase rates on the discharge of the terminals, and basically see what capacity is available through the DRA expansion. And then I think your second question was on is there something larger for Seaway, with additional expansion, and we do have a horsepower expansion that's in development right now as well.

Okay, but not adding another pipe. It would all be DRA and horsepower.

Yes, the DRA one we talked about and the horsepower would just be on the existing pipe.

Second question, just on NGL marketing at a high level, how repeatable do you think the Q3 results -- they were quite strong. How repeatable are they for the next few quarters if market conditions stay tight on NGL pipelines and fractionation?

I think we're going to have a good -- I think the future looks bright for us. The fundamentals are in our favor.

Your next question comes from the line of Danilo Juvane with BMO Capital.

Randy, clearly, you outlined that you're not in favor of doing buybacks right now, but how do you think about the dividend growth in 2019?

I think where we are -- again, I come in -- we're in a great place business environment-wise to come in and see good places to deploy capital from a growth CapEx standpoint. We're -- Jim earlier talked about that we're on track to have 20 consecutive years of distribution growth. Probably this time next year, we'll be talking about 21 consecutive years of distribution growth. But as far as -- I think we want to really stick with our timeline as far as coming in and what level of distribution growth that we see in 2019. We'd really like to come in and get through our planning process and see where we shake out on some of these larger projects that Jim talked about. The one thing that we're -- we do have a goal of coming in and equity self-funding, but at the end of the day, we're not going to let that goal put a limit on what we're going to do on organic growth CapEx when we have good projects. So right now there's still more to come, and we need to complete our planning process. But, I mean, we're -- I mean, organizationally, business-wise, we're in a great place.

And as a follow-up on the equity NGL volumes, should we expect you to continue to sort of have lower volumes like you did this quarter until Shin Oak comes online? How should we think about that?

I think about it in terms of fractionation more than once Shin Oak comes online. And lower equity volumes does not mean lower margins. We're pulling triggers that give us higher margins than those equity volumes. Whatever we're replacing those equity volumes with, you can bet we're making more money than we're taking out of our pocket on those equity volumes.

Okay, so the volumes should improve, then, once one of your fracs comes online at Belvieu there.

It's hard to hear you. I'm sorry.

So I asked that the volume should improve once one of your frac facilities -- new frac facilities come online at Belvieu.

You're right.

This is Tony. I just want to add something, because this equity volume thing keeps coming up. At the end of the day, liquids production in the United States continues to grow to beat everyone's expectations, so that's the reality, and there's not a reason for it to slow down at this point. So those barrels go somewhere, and they keep coming.

Danilo, if we choose to lower those equity volumes, it's either replaced with the customer's volumes -- and you know our system. There's also an opportunity to bring purities out of Conway. So that's just the optimization game that we do every day.

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

Congrats on a great quarter. A quick question for you. When you're signing fractionation deals, how different is the tenure of the contracts you're signing these days relative to what you may have started signing when you first started the significant build-out at Mont Belvieu?

It comes and goes, really, and sometimes it's dedications and sometimes it's demand fees, and both have their positives. So it's kind of -- we take the Forrest Gump approach. If they want vanilla, we're going to sell them vanilla. If they want strawberry, we'll sell them strawberry. I am see -- we are seeing a little more demand fee requests.

And can you talk about length of contracts? You just gave great detail on kind of type of contracts, but, I mean, average contract in the 5- to 7-year range or much significantly longer than that?

We like 10-year deals. If it's a 5-year deal, it's a different fee than if it's a 10-year deal. But we like 10-year deals.

Your next question comes from the line of Becca Followill with U.S. Capital Advisors.

It seems like the pipes and fracs are chock-full. Can you talk about where you have remaining operating leverage of volumes, besides the Eagle Ford?

That's pretty much it, Becca.

Hey, Nicole, we have time for one more question.

Certainly. And your final question comes from the line of Sunil Sibal with Seaport Global.

My question was related to your crude segment, the $200 million mark-to-market loss that you had in the press release. I was wondering if you could talk about the duration of your remaining basis hedges on crude. I mean, how much time those basis hedges run through.

If you look at the kind of life-to-date earnings for mark-to-market on these hedges, including the $204 million gain this quarter, it's about $309 million that's left outstanding, and we expect to get about $167 million of that back in the fourth quarter. And in 2019, we should get $137 million and then in 2020, $5 million into that. That assumes there's no price differential changes, which is probably not a good assumption to the extent if spreads widen further, we could see additional mark-to-market losses, or if they narrow, we could see gains.

And then on the crude segment volumes, it seems like there was a bit of a decline sequentially, both on the main terminal volumes as well as the pipeline volumes. I was wondering was there any kind of big trend which determines that?

I think on the crude terminal volumes, there was a period where the Chinese stepped out of the market in August, and I think there were some barrels that stayed here before vessels got repositioned. Then you saw kind of a big uptick in September as they started coming back.

Okay, and that reflected in the pipelines also, I guess?

Yes, I would say there was -- the arb wasn't as wide open on Seaway as it is right now, and I'd say Eagle Ford, quarter-over-quarter, stayed flat.

The bulk of it is Seaway.

Yes. Seaway -- there was a period of a couple months in there where the tariff wasn't justified versus the arb.

Nicole, if you would, would you give our listeners the replay information? And then that would be it from the company. Everyone have a great day. Thank you.

Thank you for participating in today's Enterprise conference call. This call will be available for replay beginning approximately an hour after the end of today's call and ending on November 7 at midnight Central Time. The conference ID number for this replay is 9969565. Again, the conference ID number for this replay is 9969565. The dial-in numbers for the replay are 855-859-2056 or 404-537-3406. Thank you for participating in today's call. You may now disconnect.