Good morning. My name is Erica, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Third Quarter 2017 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Randy Burkhalter, you may begin your conference.

Thank you, Erica. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss third quarter 2017 earnings. Our speakers today will be Jim Teague, Chief Executive Officer of our General Partner; and Bryan Bulawa, our Chief Financial Officer. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn it over to Jim.

Thank you, Randy. Our businesses continued to perform in the third quarter in spite of the fact that everyone on the Gulf Coast was impacted by Hurricane Harvey and the Enterprise, our employees and our customers were no exception. In spite of the hurricane, Enterprise reported $611 million of net income, distributable cash flow of 1.1 billion, 1.2 times coverage and a 152 million of a repaying distributable cash flow. The solid results for this quarter were supported by increased volumes on our liquid pipelines and marine terminals. Our NGL, crude oil and refined product pipeline transported over 5 million barrels a day of liquids and our marine terminals handled 1.3 million barrels a day. We continue to see increased liquids production in the Permian basin and new volumes from growth project that came online over the last year. We believe than an improving commodity environment coupled with strong demand for U.S. exports, new demand from new ethylene plants and several of our major projects coming online should help increase our DCF in the future. Our press release notes that our third quarter net income was negatively impacted by about $35 million because of Hurricane Harvey, while it was a catastrophic event that impacted the entire Gulf Coast, our systems and the truly special employees that run them are in the significant amount of goodwill with our customer. Since I don’t know how to describe what I witnessed in those five days of chaos, I will take a minute to read a very small sample of what our customers said about how our employees performed and what it meant to their companies. A Permian producer wrote, we owe your team a sincere thank you for the efforts Enterprise has taken over that last two weeks to keep our production moving.…

Thank you, Jim, and good morning everyone. I would like to reiterate Jim's earlier comments that we're very pleased with our financial performance during seasonally weak third quarter where we endured an estimate of $35 million headwind named Hurricane Harvey. Again, we demonstrated to our customers and stake holders alike, the reliability and durability of our business model, and have been said that, I will review a few income statements items for the third quarter providing update on our growth and sustaining capital expenditures for the remainder of 2017 and wrap up with an overview of our balance sheet metrics, capital raising activities and an update on our distribution reinvestment program. Starting with income statement items, net income attributable to limited partners for the third quarter of 2017 was $611 million or $0.28 per unit on a fully diluted basis compared to $635 million or $0.30 per unit on a fully diluted basis for the third quarter of 2016. Net income attributable to limited partners and earnings per unit this quarter included the abovementioned estimated impacts from Hurricane Harvey $35 million or $0.02 per unit. Of this amount, approximately $30 million represents the combined net impact of reduced throughput volumes and loss business opportunities. The remaining $5 million represents expenses we incurred during the quarter in connection with hurricane related repair and recovery cost. Depreciation, amortization and accretion expenses were $21 million higher when compared to the same quarter of 2016, primarily due to assets being placed into service such our Morgan's Point Ethane Export Terminal and EFS Midstream projects and several crude oil terminal expansions. Total capital spending in the third quarter of 2017 was $1 billion, including $54 million for sustaining capital expenditures. For the full year of 2017, we currently expect to invest in the range of…

Thank you, Bryan. Erica, we're ready to take questions from our listeners now.

[Operator Instructions] And your first question comes from the line of Matthew Phillips.

Quick couple of questions on the crude segment. It seems like you all had a seasonally size missed on mark-to-market on marketing gains in that segment and the quarter. I was wondering, if you could go into that a bit? And then second, we've hit record U.S. exports on crude in the past week here, obviously, Brent, you're further driving a big portion of that. How would you see that affecting your systems including Seaway and the South Texas asset?

In terms of mark-to-market on the crude oil, so we do a normal purchase almost sale on one commodity and we sell crude against it. So anytime there is a rising crude environment, we're going to lose the mark-to-market. We will see that down the road as these hedges come to fruition. Then on the export piece, if we look at Enterprise's marketing activities on the crude oil, for last two months, we have one term barge deal in the Gulf Coast that we do a few barges to refinery. Every other barrel, we have not sold domestically. It's gone cross our docks. So in terms of exports, if you look at how we're positioned, if you look at the dock presence, you guys have heard us say this before but we view that as a magnate for everything that comes from Midland or from Cushing. Seaway values are back to where they were a few years ago, Midland and Houston was at levels we haven't seen for quite some time. So, reason for all that is because of that access to water and that’s where we've positioned ourselves and we're going to see the benefits of it.

So, you haven't seen too much benefit of that in 3Q, but you expect more going forward?

Yes.

And your next question comes from the line of Tristan Richardson.

Just curious in terms of you guys have done a lot in terms of balancing retained cash flow with capital deployment and over the long-term -- going forward, and just kind of curious. How that overlays with your view on the universal project out there and project return profiles with this self-funding goal by 2019 in line?

This from our standpoint is we’re seeing a lot of good growth opportunities and when we come in again a little bit it goes back to the conference call, we held a couple of weeks ago. When we come in and balance off, is the market given us credit for the distribution growth versus retaining some of that distributable cash flow back in the business and reinvesting it back in our growth projects. And when we look at it on balance, we think we’ll get a better long-term value by moderating the distribution growth and retaining more the capital, and reinvesting back in the business. I think I will say this we've gotten a lot of positive feedback on the step that we took there. And the one thing I want to make sure people understand, the biggest driver of us being able to come in and get to a self-funding for our equity needs is the expansion of distributable cash flow per unit that we expect to see over the next four years. And then if you would, the moderating, the distribution growth is the icing on the cake. Jim?

Thanks, Tristan. My sense is one of your -- part of your question was, what kind of projects do we see? Is that right?

Jim, more just on the concept of project returns. You’ve done a lot to supply retained cash flow to fund projects. Anything on the project returns side changing metrics hurdles etc?

Yes, I think we said in the past and I think Bryan has spoken to it. It’s no accident that you’ve seen us move to five to six years ago and having no deepwater ship docks to now having 19 that was by design, that’s more to duplicate or anyone. You've seen us built the PDH plant that’s going through off quite a bit of cash or I guess Bryan we got all the permits for the iBDH plant. So we will be starting construction on that. So those returns are typically better than what we can expect, if we're out there fighting with others on gathering systems in the Permian through acquisitions with the PE companies.

And your next question comes from the line of Shneur Gershuni with UBS.

I was wondering if we can go back to I believe its Bryan comment about the DRIP program and so forth and in context to being self-funding. Do you still need the DRIP program in ’18 and ’19 to be self-funding? Or do we see that actually eliminated at some point?

Shneur, this is Bryan. As far as for 2018, we would need the participation of that not sort of participation levels we see next year which has been around $90 million to $95 million per quarter. But if they were to delve back to what was typically a $65 million to $75 million per quarter type of expectation that probably would take of our needs for 2018 or 2017, and we would probably need less of that in 2018.

Okay, great. And then I was wondering if we can talk about NGL for a minute here. Obviously, they have been weak for the last couple of years and I believe you do have some sensitivity to it. And I think it kind of goes to the prior question about returns where you turned on a lot of projects but the returns haven't been there. And I suspect that some of it has been that you had the weakness in other areas like the NGL side. With NGL pricing straightening the way it has been and expected to continue to do so. Do you see from sort of operating leverage as you sort of look forward to 2018 as there some sort of sensitivity that you can demonstrate for us and illustrate I guess?

Yes, Shneur, coming back in and taking a look at that, if we look historically and I want to say from 2010 through 2014 call it. We saw a big expansion call it almost a 10% compound annual growth rate in distributable cash flow per unit. And you’re right, since 2014 we may be down about 6% as far as at distributable cash flow per unit, but a lot of that is the headwinds that we've seen going through this cycle and our commodity sensitive businesses. So if you come back and look a little bit from peak to trough, if you would, 2011 through 2016, roughly the headwind that we thought in the NGL business the gas processing business and our obtain enhancement business is between $750 million and $800 million. So that almost equates the $0.37 per unit as far as the headwind that we've been fighting. So our expectation is as we come in and see processing margins improve, we may be able to come back in and get some of that back. How much we're going to get back? We'll just have to wait and see.

So, it's fair to say that, so you really have seen strong returns on the new capital that was put in service in '15, '16 and throughout '17, but rather it's been overshadowed by the NGL headwind. Is that a fair way to characterize that?

I think it is though. I think if you come in and if you come in and say from 2014 to 2016, we may have seen a distributable cash flow from unit to be down, like I said 6%. So, we're talking in the neighborhood of maybe $0.12 per unit. But some of that is in the background that you had a $0.37 per unit headwind from lower gross operating margin from gas processing and from the octane enhancement business. And so, that wasn’t the only headwind we were fighting but certainly that was the largest.

Can we assume that same 6% is the upside potential as NGL prices begin to normalize and other commodity prices?

No, I don’t know if you're going to -- we've certainly seen it where we've seen the improvement this year and certainly the second half of this is from propane plus. From processing margin standpoint, you would not have necessarily seen the pickup as much on the ethane side yet. So does that help?

It does other than in absolute number, but I am sure you won't share that.

Yes, I will go back and say one more thing. When you come in and if you just look at our returns on capital, our returns on capital the last couple of years and I mean this is 2016 and the trough of the cycle, our returns on capital are comparable to what they were re-financial prices. So, we saw and our returns on capital went up in that 2011 through 2014 time period, but those were when you were at some pretty heady natural gas processing margins and again your commodity sensitive businesses were performing well. But the returns on capital overall for the Company are back where they were like I said re-financial prices.

This is Jim. To the Randy’s point, you see propane trade today at 75% of crude brent whereas with no longer trade 50% of credit. Ethane has not benefited, but then you just now see in all these ethylene plants come on. So once all those ethylene plants come on, there is a pretty good appetite for ethane to give that we’re going to see an uptick there.

Okay. I’m happy to hear you guys said that. I thought your returns were strong and it was overshadowed and I know there is narrative that suggest otherwise, but happy to hear you confirm that. Just a final question, your comments about Shin Oak about right away secured and long-lead time equipment ordered and so forth. Obviously, you are planning to move forward with that, but does that still preclude the potential either at JVing or trying to do a joint construction effort with any other parties that might be interested in doing that to try bring down the cost or the plan is that and it's moving forward as it?

We’re always flexible and they're willing to talk to anybody. Right now, we're building the pipe and we operate what six pipes across West Texas between our crude, natural gas and NGL pipelines like that’s a pretty good franchise for us. It’s not just a Permian pipe in our comment we mentioned, we’re seeing grow and production out of the Rockies. And frankly what we've got across West Texas is pretty much full as we speak. And once before this pipe will be comes on, I think we’re going to have our existing pipes chockablock pull.

And your next question comes from Jean Ann Salisbury with Bernstein.

On your Permian projects, it seems like Kinder Morgan is very close to FID on their gas pipeline to Agua Dulce. Are you getting the feel from customers that the market can support two lines to Agua Dulce. And would Enterprise have any flexibility to change the delivery plant to Katy?

Hi, this is Bryan. To the total appetite of what I call residue gas at Waha, yes, I think there is a lot of appetite for a second pipeline. Actually I’m on this call and frankly I was invited to go talk to producers about the pipe across the state of Texas right now, so I am missing that on that right now. So then we talk about an appetite for the Katy versus Agua Dulce. You know Agua Dulce obviously for our system on the Gulf Coast is the advantage not go to, would preclude DeLaney, Katy? No, but as you’ve heard before we’ve got a portfolio of projects across all of our business models. So, we're pushing really hard to get something done to Katy, no, but we still take a look at it for sure.

Okay, that’s helpful. And then on Shin Oak, it seems like the last quarter wasn’t great news. Target got a partner on their pipeline and Epic who I previously thought wasn’t that real snagged BP as an anchor shipper of their project. I mean it seems like as you said, you have enough processing to fill Shin Oak yourself, but some of your other NGL pipes out of the Permian could feel the pain to shift these others are available. Is that a fairway to think about it?

No, fairway to think about it is, we don't fill our pipe.

And next question comes from the line of TJ Schultz with RBC Capital Markets.

Just first question and follow-up on crude exports. Any physical constraints that you're seeing either on your end or within the industry with the re-concerns? And then what do you think as the sealing for crude to clear on the water out of the U.S. before any physical bottleneck?

I don’t know what the answer of second TJ, but on the first one. We still got plenty capacity. We only have the ship channel docks, we've got the our docks in Beaumont that has capacity and we got docks in Freeport in Texas City as a apart of Seaway joint venture that has capacity. So we don’t see -- we don’t have any constraints in the near-term, do we Tony?. So your second question Tony, what that was I don’t know?

We feel strongly and we talked about it a lot during the Analyst Day that the incremental crude oil that the U.S. is going to produce at these kind of price levels is going to be exported. So we're not surprised to see the 2 million barrels that the EIA is reporting and the increase is week or week. And there is -- the fundamentals are fairly simple. There is substantial more. There is large amount to come.

I guess just from the follow-up question for me. You talked a little bit in the prepared remarks about the Eagle Ford, obviously competitive market there on Midstream. If you could just expand on some of the conversion opportunities that you mentioned capitalized on some of the lean gas kind of what's driving that? How big of an investment? Is it for the conversations and what's the potential benefit?

Let me take shot at it, Bryan, over to you. It's not a lot of money, I think all it is putting in a treater, Brad and changing services on some rich lines installing.

It’s a fairly chip conversion, it's nice luxury to have large diameter pipes in the same ditch for you can find a flip flop the services from rich to lean and pretty easy basis. And as Jim said, build on an aiming treater, we already have a surfer side -- very, very chip expense to get into the lean gas gathering business on South Texas.

I don’t know TJ there is going to be a huge benefit but it's going to be a benefit.

And your next question comes from Brian Zarahn from Mizuho.

So following on Permian and NGL takeaway. So previously we discussed Houston versus Corpus for Permian crude volumes, but we'd appreciate little more color on, how you view the attempt by some -- for Corpus to be a home for NGL?

Well, I'd like to see where the Mont Belvieu of Corpus is. The Mont Belvieu the hub for NGLs and if you're going to be affected and successful, I think you're going to be that way in Mont Belvieu. I don’t think anywhere else compares with it. Anybody?

This is Bryan. But I always look at Corpus and I’m a producer I like on flow assurance. I’m a trader I like it arbitrage opportunities. So if I am a producer back in pipelines albeit heck of a lot more concerned about flow assurance.

End markets, every petrochemical on the Gulf Coast is tied to Mont Belvieu, so -- and all the takeaway pipe come out of Mont Belvieu. In storage and God knows more storage…

Yes, this is Tug. I'll just add that if you -- you saw very recently with Harvey, if you're dependent on the pipelines feeding the frac and that frac goes down. You don't have access of that storage or back and back up to producer. And drain harder with exercise all the storage on Mont Belviue and keep our pipelines up. So storage is the key.

So, it's fair to say that you're potentially skeptical on these projects to Corpus actually going ahead and/or that there will be enough production growth to both on the Permian and the Rockies to provide adequate volumes for your system?

We’re not going to be building anything in Corpus.

I guess shifting back to the distribution policy change and I understand you want to preserve your flexibility in 2019. But as of today, would you lean towards potentially resuming your prior distribution growth? I know you threw out buybacks or would you just continue to reinvest?

I think we’ll need to see what our opportunities are once we get out 2019 and 2020. So, it’s hard to speculate at this point in time, but…

Fair enough and congratulation to the World Series champs.

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

Hi. Good morning. First just wanted to clarify on 2018 equity. Bryan, I think you said the needs right now if you had 75 million per quarter of DRIP that’s all you need. So can I say no at the market issuance at all in 2018 based on the current plan?

Based on if assuming there's couple of moving parts obviously is as long as we stay within the range of $2.5 billion to $3 billion on CapEx for next year that I mentioned. And the presumption that we will have a Midland-to-Sealy and PDH up and operating, if that is the case, it would appear on what we’re looking at today in the environment that we’re looking at that would be the case.

Okay, great. And second question just on Midland-to-Sealy. You talked about the piping limited until the second quarter. Are you just limited on backing capabilities, but you could still get decent utilization Q1? Or should we really be assuming that the pipeline runs very well until Q6?

I think we’ll have decent flows, but we won't be able to do as the batching that we’re contracted to do until early second quarter. Is that right Brent?

That's right.

And your next question comes from Jeremy Tonet from JP Morgan.

Just wanted to touch base on ethane rejection levels, if you could share some details as part of how it was in the quarter? And how that compares to where it's been? And any improvement, do you see anymore recovery? And kind of where do you expect that to go with these crackers starting to come online?

Sure. I mean, this is Tony. I will take that. What we see on ethane and really just using our own pipelines and tracks as the bad weather. Is it comes and goes almost day in and day out based on economics? But the number is still large, call it greater than 0.5 million barrels a day, we believe. But if you look at what's happening with the cracker, we think that number is going to come down substantially, by the end of 2018, we will have 0.5 million barrels of incremental ethylene cracking online. So should be real positive for producers of it of ethane. With that said, we think there is considerable upside as far as production for the ethane molecule because so much of it comes out with shale gas. So, we've been fairly open that we think and we call it 2021, 2022 on frame. U.S. will start trending along ethane again. Jim, did I miss anything?

Yes, there is plenty of ethane that who is going to benefit is that mean you’re going to get some margin improvement and this is going to be driven by how far out we have to reach to get it. So if you’re positioned in the Eagle Fort of the Permian, I think you’re going to be felt pretty good about the ethane, and if you're in Marcellus, not so much.

That’s helpful. Thanks. And then going to the press release on the crude oil type segment, you noted that contributing to the reduction in gross operating margin was a 39 million decrease from other marketing activities impacted by lower crude oil sales margins. And I was just wondering what were you making on Q3 of last year that you weren't making this year? And what was the level of profit for that quarter for that activity.

I will tell you what I'd like first shot at it and then follows up. I think some of the opportunities that we saw a year ago as you had more contango type of opportunity a year ago compared to this year. And then probably you may have had also more blending opportunities a year ago compared to what you had this year.

I think if you look at I don't know we call it, back in February it was January of last year, that’s one kind of hit the low's of at 27 bucks or so. We put on some contango trade that went all the out to the third quarter that came to fruition, last year. So, that’s to Randy's point. And then some of the activities as we mentioned, there's some Seaway deficiencies that we utilized for the third quarter. So that wasn’t recognized in the past and so when margins weren't that great on Seaway, in 1Q of this year and 2Q of this year, we held back on shipping. And then we kind ramped the back up in the third quarter of this year, you will see it in the fourth quarter also to some extent. And then also at our mark-to-market activities, we talked about when crude goes up, there is another commodity that we saw against crude. Then also on our hedges for Midland to Huston is WTI to Brent lines out or Midland NEH lines out. And I'll say those two are pretty close to same thing. We hedged some barrels earlier at margins that were less from where they are today. So that’s a high-class problem because we got more hedges to go, but those would show up in the crude results.

Could you give us any color on just how big this is as a contributor to the $200 million of EBITDA thereabouts for the quarter these type of activities?

In terms of which hedges?

I mean crude marketing is, is it 10%, 20%, any color you can give us as far as it's a segment margin there?

No. It’s not that much, Jeremy.

No. Crude marketing for us is you guys know our game plan, it’s to fill up empty holes whether its storage whether its pipelines. So, we just -- we’re kind there to backfill, but in terms of the projects that we do, you guys have seen our game plan in the past. I mean our goal is to stop those assets whether its storage, whether its pipelines, and then enterprise marketing comes back in there to back fill.

Got you. So, it sounds like crude marketing by the way nice contributor 3Q ’16 but it is some 5%-ish something like that this quarter?

I don’t know the percentage, but again we’re there to fill holes. So when there’s contango, crude marketing fills holes and tanks. And then when there’s pipeline orb opportunities Enterprise marketing subs up and fills those holes.

I think maybe we need to answer your question. Crude marketing is not a business. Crude marketing is a part of the business. Enterprise didn’t have a centralized marketing group that has their own P&L. Any marketing activity is a bit -- our NGL marketing activity is a part of our NGL business. Our crude oil marketing activity is part of our crude oil business. So they’re supportive of the assets, they’re not there to make a boatload of money there. They're to fill up pipe and fill up storage and fill up export docks. Does that help?

That’s helpful. Thank you.

And your next question comes from the line of Nick Raza with Citi.

Yes. Most of the questions I had been answered. I just had a couple of follow-ups. Really, quickly, just in terms of the Seaway pipeline, a competitor of yours [indiscernible] specifically has gone out for open season. Could you just speak what you’re seeing? And what do you think the competitive dynamics will be going forward just for that route from say Cushing to the Gulf Coast?

Yes. This is Brent, again. We’re evaluating the terrace we have on there. Right now, we’re lower than our competitor. I mean value of Seaway. You tell me what Brent to WTI does? And I’ll tell you what the value of Seaway does. So ultimately, I think we benefited because of our presence on the water. So I think Seaway is part of it in terms of going from Cushing to Houston or going to Cushing to Gulf Coat. But ultimately, I think where we’re going to benefit is by our presence on the water.

Also we have -- Brent is right, the other thing is we’ve got the right partner because he has the pipe out of Canada and he is positioned to bring Canadian crude into Seaway down to the Gulf Coast.

Got you.

We go back to your question because somebody asked me this question awhile back is, Enterprise marketing has a Seaway commitment that rolls off here in January of 2018. And somebody actually asked me, if we were going to re-up our commitment which if you would ask 12 months ago, I thought that was a crazy question, but it does make the question. But to answer of that we’re not going to re-up our commitment.

Okay. That’s helpful. And then I guess, just turning to one of your projects and development, the ethylene export. In terms of just looking forward and timing, what sort of milestone should we look at? I mean you already put in some of the supporting infrastructure pipeline for storage, but in terms of the export docks. how do we view timing on that?

First, we got to firm up the contracts, but it assumed that goes forward from the date we sanction it what are you looking at timeline.

It's a total of the two-year project.

Okay two years and obviously, it's going to be complete key base and would EPD's marketing entity enrolled and take out sort of capacity on that or would it just be third party?

We don’t necessary have to take out capacity. We typically use available capacity. To the extent, we can contract it forward in our yield take out capacity consistent with that contract.

[Operator Instructions] And your next question comes from the line of Darren Horowitz from Raymond James.

There has been a lot of discussion around marketing activities and the sensitivity on gross operating margin. And I want to just try and tie everything together to make sure that I understand it. If we think about your results to-date and let's just say how specifically try to assume the 70% of your NGL marketing is LPG exports, right, which is just contracted fully but long duration. And of that remaining 30%, the bulk of that cash flow reflects back to back contracts for asset optimization across a verity of commodities. Then, is it fair to assume that your true non-LPG export NGL marketing is only really about 5% of total gross operating margin?

Where you've been Darren? Well, it's expected to be the first question. You're pretty close Dan.

Okay, I just wanted to make sure that I understood it. My second question, Jim, just what everybody is asking what’s next, as you think about getting deeper into turning purity NGLs into higher value olefin. What makes sense for you? Is it conversation of butane or isobutane into alkylate or maybe you consider a joint venture for alkylate export with let's just say hypothetically a non-North American alkylate consumer? Or where else do you want to be in the value chain?

I like -- we’re not there yet, but I really like the idea of -- if we're going to move further into petrochemicals, I like the idea of logistics. So this hoping of ethylene storage and pipe, I will like that. It's been trued to who we're and it's a natural extension of what we do well. I like the idea and our base has been pushing hard of exporting propylene. I like the idea of developing a propylene market hub and an ethylene market hub because that’s been trued to who we're. So we like the idea of play in a role in the storage and logistics.

And your next question comes from the line of Colton Bean from Tudor Pickering.

Now, we're running a little bit long here so I'll keep it to one, but just to follow up on the NGL. I think and it seems like a lot of questions have centered around pipe capacity coming out of the Permian. But if you follow that through to its logical conclusion downstream, it seems like there is lot of opportunity in the fractionation and at least for a C3 plus maybe even on the dock capacity side. So I guess maybe some of your question for you. How do you guys view the impacts of ramping NGL production on downstream opportunities?

Well, we’re very open, we pushed how we see it falling down and we're not saying falling I mean growing. And we see the key falling I mean the numbers are going to come out of the shells particularly the Permian Basin and out of the EU for their large and they need markets. Those markets can either be to upgrade those molecules in the U.S., use some here and then export them or there will be exports because we believe they’re coming especially with the improved ratios to include that Jim talk about.

Yes, we’re building up knight fractionation trend out of Mont Belvieu. Right now, we have the 10th permitted grant. We got the 10th permitted and we got a chairman that loves fractionation.

And I guess just a follow-up on that. The thing you got LPG exports specifically you guys going to have your demand ramping up here with the PDH facility, but beyond that it doesn’t look like there is a whole lot of domestic uplift over the next couple of years. So maybe late decade or early next decade, if most of those propane and butane molecules are finding their way across the dock, is there any potential for pricing power to come back in the space there?

Well, I hope so.

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

Just a follow-up to your couple of earlier conversations. Bryan, I guess just a sort of go on it in terms of the DRIP, so when you get to 2019 and your self-funding. Do you anticipate still having the DRIP out there? Or you think you’ll shut the DRIP off?

I would anticipate that it’s still one of those things that we would remain in place. I think it’s been an attractive vehicle for existing and long-term unit holders and I don’t see it going away. But the reliance upon it will less than and will see, it’s a nice vehicle to have as we look out at well.

Okay. And then back to Seaway for a minute, so you said the Enterprise marketing will not re-up the contract when it comes out. Is that because you think you’ll just be able to shell out that out to third parties?

I think there is a lock-up term that we want to participate. We'll participate that way. There is part of opportunity to sell long term to third parties as capacity rolls off. And the issue with Seaway is, there is more capacity that is coming on line. So in terms of excess capacity is probably not a whole lot for another year or two. There is lock-up space obviously. And at the end of the day, if Enterprise chooses to participate that, we'll participate as we offer dock services to people.

We have time for one more question, Erica?

Yes, your last question comes from Danilo Juvane with BMO.

Very quickly on LPG export. What you guying seeing byway of spot margins currently, those going up here over have they remained relatively the same over the last couple of quarters?

I'd say, they're hold and steady. I think a lot of opportunities probably range between $0.05 and $0.07 gallon. So we -- Tony and I don’t talk about, but you look at Tony's fundamentals forecast and Tony's diagnostic to thing, but his forecast happens to show that we're short dock capacity as U.S. about the same time our contracts roll up. And I've had more than one customer coming out on that, but right now it's $0.05 to $0.07. We will see where it goes in 2021 when our contracts roll off.

Got it. And with propane prices where they are today, I think they had a $1 last, but you don’t see any risk of cargo cancellations or anything probably remaining on the heating season here?

So last year I think for our first quarter, if I recall correctly, we had one cancellation in March. Our belief is that there is quite a bit of in the last take demand out there. So if you look at various tranches, if you say certain demand is in the last take and then, as you started going against another commodity, our belief is that propane still has a way to go before it gets priced out of exports. So if you look at PDH plants over in Asia, we could see propane still has more room to go.

Thank you, Eric, if you would -- would you our listeners the replay information and then that will end the call today. Thank you.

Thank you for participating in today's conference call. This call will be available for replay beginning at approximately 1 o'clock Eastern Time and until end of day November 9 2017. 49822182 is the access code for the replay. The number to dial for the replay is 855-859-2056 or 404-537-3406. Thank you and this does conclude today's conference call. You may now disconnect.