Enterprise Products Partners LP (EPD) 2017 Q3 法說會逐字稿

Good day. 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. (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, 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 well in the third quarter in spite of the fact that everyone on the Gulf Coast was impacted by Hurricane Harvey and 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 $152 million of retained distributable cash flow. The solid results for this quarter were supported by increased volumes on our liquids pipelines and marine terminals. Our NGL, crude oil and refined product pipelines 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 projects that came on line over the last year. We believe that an improving commodity environment, coupled with strong demand for US exports, new demand from new ethylene plants, and several of our major projects coming on line should help increase our DCF in the future.

Our press release notes that our third quarter net income was negatively impacted by $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 earned a significant amount of goodwill with our customers. Since I don't know how to describe what I witnessed in those five days of chaos, I'll 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 the last two weeks to keep our production moving." An integrated major, "we want to know how you did it. You continued to operate throughout the storm." An Eagle Ford producer, "we appreciate the great service during Harvey. Enterprise stood out as the premiere processor in the Eagle Ford." A US Gulf Coast refiner," you guys are awesome. My profound thanks to all who worked on helping us get our refinery up." And finally a Permian producer, "thanks for all your work by your operations team to keep our production on. You guys are the image of operational excellence."

We want to acknowledge and thank our employees for their remarkable efforts during Hurricane Harvey and its aftermath. Their efforts allowed us to preserve the reliability of our midstream system despite over 50 inches of rain at Mont Belvieu and provide critical services to both our producing and consuming customers. People show what they're really made of, not during good times, but during the hard times. Our employees took care of each other. Our employees took care of their communities. And as you can see from the quotes, our employees took care of our customers.

I can appreciate that most of you on this call have no way of putting this kind of an asset in your models. But I have never experienced the dedication and heart like I saw from our Enterprise employees. As Randa said after one conference call during the height of the storm, her quote, "we work with such an awesome group of people."

Now moving to major projects. We're excited that two of our largest projects are coming online. We're bringing the initial phase of our Midland-to-Sealy pipe on line as we speak. I think the key word here is this is the initial phase as volumes and level of service will be limited until all of the tankage and pumps that support the pipe is complete, expected to be in the second quarter. We're also in the process of bringing up our PDH plant. The plant is in the startup phase and anticipate it will be at full rates before month end. Everyone knows that we've had our challenges with this project, but the fundamentals that underwrote the investment remain strong, including strong NGL supply growth and a heavy concentration towards ethane cracking by US petrochemicals, which leaves the space short of propylene. Couple that with rising global demand for propylene and its derivatives, and we believe the long-term outlook for propylene is strong.

These same fundamentals, abundant US NGLs, and growing global demand also support our iBDH plant, which is expected to be up and running in early 2019. We continue to lay the groundwork for an ethylene storage and distribution system which would include an export terminal. We plan to convert a high capacity ethane storage well to ethylene and lay an ethylene pipeline from Mont Belvieu to Bayport, routing it through the Houston Ship Channel in Morgan's Point. While not yet a firm project, we continue to make progress.

Moving to supply-oriented projects that are under construction, our two Orla processing plants and our Sand Dunes gathering system are under construction in the Delaware Basin. When Orla II is complete, expected in the third quarter of next year, we'll have over a BCF a day of processing capacity or more than a 150,000 barrels a day of NGL extraction capacity in the Permian.

In addition to our crude oil footprint, our goal in the Permian is to build a network of plants and pipes, connected to our value chain, similar to what we have in South Texas. Work is progressing nicely on our Shin Oak NGL pipeline, where a substantial amount of the right of way has now been secured. Long lead-time equipment has been ordered and completion is expected in the first half of 2019. The Permian Basin continues to show significant upside potential and Shin Oak provides a critical link between the Permian and our natural gas liquids systems on the Gulf Coast.

Also want to take a minute to follow up on activities in a couple of basins where we're already asset rich. The Haynesville, where earlier this year we purchased the Azure assets, Haynesville production continues to grow rapidly, supported by some new highly skilled players who have breathed new life into this basin. From the very beginning, we've positioned our assets in the sweet spot of the basin's geology and are seeing the benefits of having our assets in exactly the right place as the basin moves into its second life. The Haynesville is another example but this time with lean gas where we have a value chain. Gathering the strategic Acadian / Haynesville takeaway pipeline that goes to real markets along the Mississippi River industrial quarter.

Moving next to the Eagle Ford, while Eagle Ford recounts have come off some in the last few weeks, at 65, they are still double what they were last year at this time. The EIA reports that there are some 1,440 DUCs in the play. Eagle Ford producers are generally focused in the oil window, but a prolific lean gas window is developing in deep South Texas. It remains a competitive environment in the midstream space, but we have the complete value chain and have been able to keep volumes in our plants steady to rising. We're also focused on converting some of our legacy assets in Deep South Texas to lean gas service to support this growing part of the Eagle Ford. We expect also that some of the major players in the Eagle Ford will likely sell their production and acreage in this improved commodity environment, just as we've seen in the Haynesville. It's likely that buyers will be much more aggressive and that volumes will ramp up after the acreage changes hands.

I also want to review a little bit on our Rockies assets that feed our NGL systems. Those Rocky assets will also feed Shin Oak. In other words, Shin Oak is not just a Permian play. It's a play all the way up to Wyoming. The Rockies are now home to a group of extremely focused, regional producers whose expertise in the Rocky -- whose expertise is the Rockies. Rig counts in Jonah, Pinedale, and Piceance have doubled since the beginning of the year. Some producers are now testing horizontal wells and our Pioneer plant is contracted to be full for the next 10 years. While these basins may not be as sexy as the Permian, they play an important role in our portfolio. As a general rule, drilling in these basins is now in the hands of regional specialists and these producers continue to bring revenues to our value chain.

And then, new observations on exports. While month-to-month statistics and global arbs will always move around, for example the third quarter data has some noise in it because of Harvey, the trends are clear. The world wants US oil and gas, US refined products, and US petrochemicals. And frankly, we have too many. At current levels, fourth quarter export activity at our docks should be double what it was fourth quarter of last year. Even more importantly, we're spending a fair amount of time with our Asian customers, primarily crude oil customers, hearing that they like what they see in the crudes that Enterprise has available at our docks. We're working hard to keep our quality consistent and desirable and are confident that there are growing markets for US barrels and that many of these new markets will be in Asia. Frankly, it's extremely gratifying to see how our export strategies across multiple commodities are coming together.

And finally, our last point this morning, after 56 years, everyone in our great city can today proudly say, Houston Astros, World Series Champions.

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

Thank you, Jim, and good morning, everyone. I'd like to reiterate Jim's earlier comments that we are very pleased with our financial performance during a seasonally weak third quarter, where we endured an estimated $35 million headwind named Hurricane Harvey. Again, we demonstrated to our customers and stakeholders alike the reliability and durability of our business model. And now having said that, I will review a few income statement items for the third quarter, provide an 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 aforementioned estimated impacts from Hurricane Harvey of $35 million or $0.02 per unit. Of this amount, approximately $30 million represents the combined net impact of reduced throughput volumes and lost business opportunities. The remaining $5 million represents expenses we incurred during the quarter in connection with hurricane-related repair and recovery costs.

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 as our Morgan's Point ethane export terminal, 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 $2.9 billion to $3.1 billion for growth capital projects. Included in that number is the $191 million we paid in connection with the Azure acquisition. We also expect to reach approximately $240 million for sustaining capital expenditures. Beyond this year, I'll reiterate comments I made during our conference call in October where we fully anticipate spending $2 billion to $3 billion in organic growth capital opportunities per year for the foreseeable future and more specifically $2.5 billion to $3 billion in 2018.

Moving to our balance sheet, at September 30, 2017, our total debt principal outstanding was $24.9 billion. The average life of our debt portfolio was 14.1 years, assuming the first call date for our hybrids and our effective average cost of debt was 4.5%. On August 7th, we issued $1 billion of 5.25%, 60-year, non-call 10 junior subordinated notes or hybrid notes and another $700 million of 4.875%, 60-year, non-call 5 hybrid notes in an offering that generated over $3.5 billion of investor demand. As a reminder, the rating agencies give partial credit to the hybrid notes, 50% at S&P and Fitch and now 25% by Moody's. Accordingly and conservatively, the blended 37.5% of equity content affectively raised approximately $638 million of equity credit. And by our math, and an equivalent common unit price of at least $32.50 per unit. Further, the hybrid issuance eliminated our need to access the equity capital markets for the remainder of 2017.

Adjusted EBITDA for the 12 months ended September 30, 2017, was $5.4 billion and our consolidated leverage ratio was 4.3 times after adjusting debt for the partial equity treatment for the hybrid debt securities by the rating agencies and reduced for cash and cash equivalents. Some of the trends we've discussed in recent quarters with respect to contango opportunities across commodities has continued through the third quarter with increased short-term opportunities. When adjusting debt for approximately $1.1 billion of what I'll call elevated working capital associated with those short-term opportunities, we're about a $600 million increase over the second quarter of this year. Our adjusted leverage ratio would have been 4.1 times. When further applying the pro forma impact of our contracted growth projects under construction, namely PDH and our Midland-to-Sealy pipeline project, our leverage ratio was 3.8 times.

For the third quarter of 2017, we retained $152 million of distributable cash flow and $533 million year to date. We also raised $95 million in net equity proceeds from our distribution reinvestment program or DRIP and our employee unit purchase program, and another $26 million through the at-the-market or ATM program, which took place prior to our hybrid issuance.

With respect to the upcoming distribution, which will be paid next week on November 7, Enterprise Products Company and certain of its affiliates plan to reinvest an aggregate of $100 million in EPD common units through the partnership's DRIP program. This continuing level of support from our general partner will significantly reduce and quite possibly eliminate our currently anticipated 2018 equity needs through the ATM program.

Beginning with the distribution to be paid in February of 2018, we are altering our offered discount for the distribution reinvestment program to 2.5%. This offer discount remains at the upper end of MLP, REIT, and corporate DRIP programs, which typically range between 0 and 2.5%.

When summarizing the steps we've taken during the quarter, such as issuing the aforementioned hybrids at historically attractive levels, where we essentially avoided issuing approximately 26 million incremental EPD common units this year, moderating our distribution growth to further our objective of balancing distribution growth with retaining sufficient levels of distributable cash flow to fund the equity portion of a $2 billion to $3 billion per year organic growth capital program without reliance upon the equity capital markets or if you will, a self-funding model, we currently anticipate reaching a self-funding equity model in 2019 with very modest needs, if any, in 2018. The compounding benefit of these steps should benefit all of our stakeholders over the near and moreover the long term in terms of value creation.

And with that, I'll turn the call back over to Randy.

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

(Operator Instructions) Your first question comes from the line of Matthew Phillips with Guggenheim.

Morning, guys. Quick, a couple questions on the crude segment. It seems like you all had a decently size miss on mark to market on marketing gains in that segment in the quarter. I was wondering if you could go into that a bit. And then second, you know, we've hit record US exports on crude in the past week here. Obviously, Brent WTI spreads are driving a big portion of that. I mean how would you see that affecting your systems, including Seaway and the South Texas assets?

Go ahead, Brent.

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

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

Yes.

Okay, thank you.

And your next question comes from the line Tristan Richardson with SunTrust Robinson Humphrey.

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

Yes, Tristan, from our standpoint as -- you know we're seeing a lot of good growth opportunities and you know when we come in and again, a little bit of it goes back to the conference call we held a couple weeks ago, when we come in and balance off you know is the market giving 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 of the capital and reinvesting it back in the business. I think -- I will say this, you know we've gotten a lot of positive feedback on the step that we took there. 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 three years. And then if you would, the moderating, the distribution growth is the icing on the cake. Jim?

Yes, I think, Tristan, my sense is one of your -- part of your question was what kind of projects do we see? And 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 return side changing metrics, hurdles, etc.?

A Yes, I think we've said in the past and I think Brent has spoken to it, you know one of the -- it's no accident that you've seen us move to 5, 6 years ago having no deepwater ship docks to now having 19. That was by design. That's hard to duplicate for anyone. You've seen us build a PDH plant that's going to throw off quite a bit of cash. We're, I guess, Graham, we got all the permits for the iBDH plant?

Yes, sir, we do.

So, we'll 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 or through acquisitions with PE companies.

Understood. Thank you guys very much.

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

I was wondering if we can go back to Bryan, I believe it was Bryan's comments 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 could we see that actually eliminated at some point?

Shneur, this is Bryan. As far as for 2018, we would need the participation at, not sort participation levels we've seen this year, which has been around $90 million to $95 million per quarter, but if it were to dial back to what was typically a $65 million to $75 million per quarter type of expectation, that probably would take care of our needs for 2018 or 2017 and we would probably need even less than that in 2018.

Okay, great. And then I was wondering if we can talk about NGLs for a minute here. You know obviously they've 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've turned on a lot of projects, but the returns haven't been there. And I suspect that some of it has been that you've had some weakness in other areas like the NGL side. With NGL pricing strengthening the way it has been and expected to continue to do so, do you know, do you see some sort of operating leverage as you sort of look forward to 2018? Is there some sort of sensitivity that you can demonstrate for us and illustrate I guess?

Yes, Shneur, you know 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 the distributable cash flow per unit. But a lot of that is the headwinds that we've seen going through this cycle in our commodity sensitive businesses. So, if you come back and look a little bit from peak to trough, if you would, 2011 through 2016, you know roughly the headwind that we fought in the NGL business, the gas processing business and our octane enhancement business, is between $750 million and $800 million. So that almost equates to $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 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?

Shneur, I think it is cause 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 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 -- and that wasn't the only headwind we were fighting, but certainly that was the largest.

So, I mean can we assume that that same 6% is the upside potential as NGL prices begin to normalize and other commodity prices?

You know I don't know if you're going, if you -- we've certainly seen it. Where we've seen the improvement this year and certainly the second half of this year is from propane plus, from a processing margin standpoint. You've not, haven't necessarily seen the pickup as much on the ethane side yet. So, does that help?

It does other than an absolute number but I'm sure you won't share that.

Yes, you know and I'd go back and say one more thing, you know 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 in the trough of a cycle, our returns on capital are comparable to what they were pre-financial crisis. So, you know, we've -- you know we saw and our returns on capital went up, you know in that 2011 through 2014 time period, but those were when you were at some pretty heavy natural gas processing margins and again your commodity-sensitive businesses were performing well. But the returns, the returns on capital overall for the company are back to where they were, like I said, pre-financial crisis.

This is Jim. To Randy's point, you know you're seeing propane trade today at 75% of crude, Brent? Whereas it wasn't that long ago, it was trading at 50% of crude. Ethane has not benefited but then you're just now seeing all these ethylene plants come on. So, once all those ethylene plants come on, there's a pretty good appetite for ethane. We figure that we're going to see an uptick then.

Okay. I'm happy to hear you guys say that. I thought your returns were strong and it was overshadowed. And I know there's a narrative that suggests otherwise, but happy to hear you confirm that. Just a final question, your comments about Shin Oak, about right-of-way secured and long lead-time equipment ordered and so forth, you know obviously you're planning to move forward with that. But does that still preclude a potential either a JV or trying to do a joint construction effort with any other parties that might be interested in doing that to try to and bring down the costs? Or the plan is set and it's moving forward as is?

We're always flexible and we'd be willing to talk to anybody. Right now, we're building the pipe. And you know we get -- we operate what? Six pipes across West Texas between our crude, natural gas, and NGL pipelines. We feel like that's a pretty good franchise for us. It's not just a Permian pipe. In our comments, we mentioned we're seeing growing production out of the Rockies and frankly, what we've got across West Texas is pretty much full as we speak, Tug? And once, before this pipe will be, comes on I think we're going to have our pipes -- our existing pipes chock-a-block full.

Perfect. Thank you very much, guys. Really appreciate the color.

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 point to Katy?

Brad.

Yes, this is Brad. You know if total appetite of what I call residue gas out of Waha, yes I think there is a lot of, a lot of appetite for a second pipe. 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'm missing out on that right now.

So, do I and do we talk about an appetite for Katy versus Agua Dulce, you know Agua Dulce obviously for our system on the Gulf Coast is the advantage spot to go to. Would we preclude going to Katy? No, but as you've heard before, you know we've got a portfolio of projects across all of our business models, so are we pushing really hard to get something done to Katy? No, but you know we still take a look at it for sure.

Thanks helpful. And then on Shin Oak it seems like the last quarter wasn't great news. Targa got a partner on their pipeline, and Epix who I previously thought wasn't that real, snagged BP as an anchor shipper of their project. 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 pen shift if these others are all built. Is that a fair way to think about it?

Well, the fair way to think about it is we're going to fill our pipe.

Okay. Okay, thank you.

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

Hey, guys. Good morning. Just first question, a follow up on crude exports, any physical constraints that you're seeing either on your end or within the industry with the recent surge? And then what you think is the ceiling for crude to clear on the water out of the US before any physical bottlenecks?

I don't know how to answer the second one, T.J., but on the first one, you know we still got -- we got plenty of capacity. We not only have the Houston Ship Channel docks, we've got -- we've got our docks in Beaumont that has capacity and we've got docks in Freeport and Texas City as a part of our Seaway joint venture that has capacity. So we don't see -- we don't have any constraints in the near term, do we Tony?

No, sir.

As to your second question, Tony -- What's the ceiling? 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 US 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 you know and the increases week over week. And there's just -- the fundamentals are fairly simple. There's a substantial for more, got a larger amount to come.

Okay. Makes sense. 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 in midstream. If you could just expand on some of the conversion opportunities that you mentioned, capitalize on some of the lean gas, kind of what's driving that? How big of an investment is it to the conversions and what's the potential benefit?

Yes, it's -- let me, I'll just take a shot at it Brad and throw it to you. It's not a lot of money. I think all it is, is putting in a treater, Brad, and changing service on some rich lines to lean.

It's a fairly cheap conversion. It's a nice luxury to have large diameter pipes in the same ditch where you can kind of flip flop the services from rich to lean on a pretty easy basis. As Jim said, you know building an amine treater where you already have a surface site, excuse me, very, very cheap expense to get into the lean gas gathering business in South Texas.

I don't know, T.J., that it's going to be a huge benefit, but it's going to be a benefit.

Fair enough, great. Thanks guys.

And your next question comes from Brian Zarahn from Mizuho.

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

Well, I'd like to see where the Mont Belvieu of Corpus is. You know Mont Belvieu is the hub for NGLs. And if you're going to be effective 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 Brent. But I always look at Corpus and if I'm a producer, I look at flow assurance. If I'm a trader, I look at arbitrage opportunities. So if I'm a producer back in pipelines, I'd be a heck of a lot more concerned about flow assurance.

And markets. You know, every petrochemical on the Gulf Coast is tied to Mont Belvieu, so and all the takeaway pipe comes out of Mont Belvieu.

And storage.

And God knows more storage.

Yes, this is Tug. I'll just add that if you- saw very recently with Harvey, if you're dependent on your pipeline feeding a frac and that frac goes down, you don't have access to that storage, you're backing all the way back up to the producer. And, you know, during Harvey we were able to exercise all the storage in Mont Belvieu and keep our pipelines up. So storage is key.

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

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

Okay. I guess shifting back to the distribution policy change and understanding 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?

Brian, I think we need to see you know what our opportunities are once we get out to 2019 and 2020. So sort of hard to speculate at this point in time, but--

Fair enough and congratulations 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'd 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 a couple moving parts, obviously. 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 full, we'll have Midland to Sealy and PDH up and operating. If that is the case, it would appear on what we're looking at today and the environment that we're looking at, that that would be the case.

Okay, great. And second question just on Midland-to-Sealy, you talked about the pipe being limited until the second quarter. Are you just limited on batching capabilities but you could still get decent utilization in Q1 or should we really be assuming that the pipeline runs very little until Q2?

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

That's right.

Okay, thank you.

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

Good morning. Thanks. Just want to touch base on ethane rejection levels. If you could share some details as far as how it was in the quarter and how that compares to where it's been? Any improvement, you've seen any more recovery and kind of where do you expect that to go you know with these crackers starting to come on line?

Jeremy, this is Tony. I'll take that. What we see on ethane and really just using our own pipes and fracs as a bell weather, is it comes and goes almost day in and day out based on the economics. But the number's still large, call it greater than a half a million barrels a day we believe. But if you look at what's happening with the crackers, you -- we think that number is going to come down substantially. You know by the end of 2018, we'll have half a million barrels of incremental ethane cracking on line, so it should be a real positive for producers of ethane. With that said, we think there's considerable upside as far as production for the ethane molecule because so much of it comes out of the shale gas. So, we've been fairly open that we think in the, call it '20, '21, '22 timeframe, the US will start trending long ethane again. Jim, did I miss anything?

There's plenty of ethane. Who's going to benefit is, I mean you are going to get some margin improvement. That's going to be driven by how far out do you have to reach to get it? So if your positions in the Eagle Ford or the Permian, I think you're going to be -- feel pretty good about ethane. If you're in the Marcellus, not so much.

That's helpful, thanks. And then going to the press release on the crude oil pipe 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 was just wondering what were you making money on in Q3 of last year that you weren't making this year? And what was the level of profit for the quarter for that activity?

I'll tell you what, I'll take first shot at it and then Brent you can follow up. I think some of the opportunities that we saw a year ago is you had more contango type opportunities 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'm trying to recall, but back in February, it was January of last year, that's when kind of crude hit the lows at 27 bucks or so. We put on some contango trades that went all the way out to the third quarter that came to fruition last year. So, that's to Randy's point. And then on some of the activities as we mentioned, there were 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. Then we kind of ramped it back up in the third quarter of this year. And you'll see it in the fourth quarter also to some extent. And then also on our mark to market activities, we talked about when crude goes up there's another commodity that we sell against crude. And then also on our hedges for Midland to Houston, as WTI to Brent widens out or Midland to MEH widens out and I'll say those two are pretty close to the same thing, we hedged some barrels earlier at margins that were less than where they are today. So, you know, that's a high class problem cause we got more hedges to go. But those will show up in the crude results.

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

In terms of these hedges?

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

No, it's not that much, Jeremy.

No, crude marketing for us is, you know, you guys know our game plan. It's to fill up empty holes, whether it's storage, whether it's pipelines. So we just -- we're kind of there to backfill. But in terms of the projects that we do, you know you guys have seen our game plan in the past. I mean we -- our goal and -- is to sell out those assets whether it's storage or whether it's pipelines. Then Enterprise marketing comes back in there to backfill.

Got you. So it sounds like crude marketing might have been a nice contributor 3Q '16 but it is sub 5%-ish something like that this quarter?

I don't know the percentage but you know again we, we're there to fill holes. So when there's contango, crude marketing fills holes and tanks. And then when there's pipeline arbitrage opportunities, Enterprise marketing steps 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 a business. Enterprise doesn't have a centralized marketing group that has their own P&L. Any marketing activity is -- our NGL marketing activity is a part of our NGL business. Our crude oil marketing activity is a part of our crude oil business. So they are supportive of the assets. They're not there to make a boat load of money. They're there 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 have been answered, but I just had a couple of follow ups. Really quickly, just in terms of the Seaway pipeline, a competitor of yours, Marketlink, specifically has gone out for open season. Could you just speak to what you're seeing and what 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 you know the tariffs we have on there right now. We're lower than our competitor. I mean the 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 benefit because of our presence on the water. So I think Seaway is a part of it in terms of going from Cushing to Houston or going to Cushing to the Gulf Coast. But ultimately I think where we're going to benefit is by our presence on the water.

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

I got you.

To get back to your question cause somebody asked me this question a while back, Enterprise marketing has a Seaway commitment that rolls off here in January of '18 and somebody actually asked me if we were going to re-up our commitment, which if you would have asked me 12 months ago I thought that was a crazy question. But it does beg the question. But the answer to 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 in development, the ethylene exports. In terms of just looking forward and timing, what sort of milestones should we look at? I mean you've already put in some of the supporting infrastructure, pipelines and storage, but in terms of the export docks, I mean how do we view timing on that?

First we got to firm up the contracts. Where's RB? Assume that goes forward, from the date we sanction it what are you looking at timeline?

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

Okay two years and obviously it's going to be completely sea based and would EPD's marketing entity be involved and take out capacity on that or would it just be third parties?

We don't necessarily have to take out capacity. We typically use available capacity to the extent you can contract it forward. Then yes, you'll take out capacity consistent with that contract.

Got you, got you. That's all I had, guys. Thank you so much.

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

Hey, guys. Good morning. There's 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 hypothetically it's fair to assume that 70% of your NGL marketing is LPG exports, right? Which is 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 variety 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?

Yes.

Yes, that's probably. That's pretty -- where have you been Darren? We always expect you to be the first question. You're pretty close, Darren.

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

You know we like -- I like and 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 whole thing of ethylene storage and pipe, I like that. It's being true to who we are. And it's a natural extension of what we do well. I like the idea and RB's been pushing hard of exporting propylene. I like the idea of developing a propylene market hub and an ethylene market hub because that's being true to who we are. So we like the idea of playing a role in storage and logistics.

Okay, thank you.

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

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

Well, we, we're very open. We publish how we see it falling and when I say falling, I mean growing. We see the key falling. I mean the numbers that are going to come out of the shales, particularly the Permian Basin and out of the Eagle Ford, they're large. And they need markets. Those markets can either be to upgrade those molecules in the US, use some here and then export them, or they'll be exports. Because we believe they're coming, especially with the improved ratios to crude that Jim talked about.

Yes, we're building our 9th fractionation train out at Mont Belvieu right now. We have the 10th permitted, Graham? We got the 10th permitted and we got a chairman that loves fractionation.

Got it. And I guess just to follow up on that, so thinking about LPG exports specifically, you guys kind of have your demand ramping up here with the PDH facility. But beyond that, doesn't look like there's a whole lot of domestic uplifts over the next couple years. So maybe late decade or early next decade, if most of those propane and butane molecules are finding their way across a dock, is there any potential for pricing power to come back into the space there?

Boy I hope so.

All right. I'll take that. Thank you, guys.

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

Thank you. Just a follow up to a couple of earlier conversations. Just, Bryan, I guess just to put a bow on it in terms of the DRIP, so when you get to 2019 and you're self-funding, do you anticipate still having the DRIP out there or do 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 unitholders and I don't see it going away. But it's -- you know the reliance upon it will lessen and then we'll see. I mean it's a nice vehicle to have as we look out as well.

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

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

Okay, got it. Thank you.

We have time for one more question, Erica.

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

Very quickly on LPG exports, what have you seen by way of spot margins currently? Are those going up here or have they remained relatively the same over the last several quarters?

I'd say they're holding steady. I think a lot of opportunities, probably range between $0.05 and $0.07 a gallon, so you know we -- Tony and I don't talk but if you look at Tony's fundamentals forecast and Tony's agnostic to this thing, but it -- this forecast happens to show that we're short dock capacity in the US, about the same time our contracts roll off. And I've had more than one customer call me out on that. But, you know, right now it's about $0.07. We'll see where it goes in 2021 when our contracts roll off.

Got it. And with propane prices where they are today, I think they hit $1 last week, you don't see any risk of cargo cancellations or anything for the remaining of the heating season here?

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

Okay, that's it for me. Thank you so much.

Thank you. Erica, if you would, would you give 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 1:00 Eastern Time 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.