Enterprise Products Partners LP (EPD) 2017 Q2 法說會逐字稿

Good day. My name is Shelby and I'll be your conference operator today. At this time, I like to welcome everyone to the Enterprise Products Partners Second Quarter Earnings Call. (Operator Instructions) Thank you. Mr. Randy Burkhalter, you may begin your conference.

Thank you, Shelby. Good morning, everyone, and welcome to the Enterprise Products Partners second quarter 2017 earnings call. Our speakers today will be Jim Teague, Chief Executive Officer of Enterprise general partner; Graham Bacon, Executive Vice President, will also speak and Bryan Bulawa, Chief Financial Officer will wrap up the prepared remarks. 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.

Thanks, Randy. Our businesses continued to perform in the second quarter continuing to benefit from our integrated assets that match supply and demand -- supply with demand across all commodities. We reported increases in all of our financial measures and most volume metrics for the second quarter compared to the second quarter last year. We generated $1.1 billion of DCF that provided 1.2x coverage. In addition, increased our cash distribution by 5% to $0.42 per unit and we retained $145 million of DCF for future growth. Work continues on several large plant and pipeline projects that we have under construction and we also continue to develop new strategic projects. During the second quarter, we approved 2 large midstream projects for the Permian.

In June, we announced our second processing train at Orla in the Delaware Basin. This 300 a day plant will double Orla's inlet capacity to 600,000 and will increase Orla's NGL extraction capacity from 40,000 barrels a day to 80,000 barrels a day. When Orla II is complete, expected in the third quarter of 2018, we'll have about 1 Bcf a day of processing capacity and more than 150,000 barrels a day of NGL extraction capacity in the Permian. NGLs from Orla will be delivered into our NGL integrated system and we're not done in this basin. In April, we announced the Shin Oak pipeline. It's a 24-inch pipeline that will originate in the Permian and transport Permian NGLs to Mont Belvieu. Initial capacity for the line is 250,000 barrels a day expandable to 600,000 barrels a day with a projected end-service time of first half or second quarter 2019.

Also in the Permian, we recently announced that we have executed additional long-term contracts for the Midland-to-ECHO crude oil pipeline that is currently under construction bringing total commitments to 335,000 barrels a day or 83% of the pipeline's 405,000 barrels a day of committed capacity. We expect initial limited service during the fourth quarter of this year. 2 years ago when we announced the Midland-to-Sealy segment of this pipeline, we said we believed in the basin and felt that the pipe was very strategic for Enterprise. We also said that we felt strongly that producer attitudes were changing with producers wanting price transparency and complete control of their barrels including segregation, storage and access to markets that include refineries and export capability.

Now as our Midland-to-ECHO pipeline comes into service, the producer community is solidly focused on completely controlling their own barrels and on exports remaining a permanent part of their own value chain. In developing our project, we planned around those types of producer wants and needs from the very beginning with expanded storage in the supply area, a large diameter pipe with significant batch flexibility, direct connections to 30 million barrels of storage at our ECHO and Houston Ship Channel terminals, access to our Houston area crude oil distribution system which accesses every refinery in the Houston, Texas City and Beaumont / Port Arthur area and access to our docks. Lastly, I'll cover today in projects is petrochemicals where we have several major initiatives underway.

Starting with iBDH, work is progressing on permitting, engineering and site preparation. Much of the long lead time equipment has been ordered and we expect this plant to be up and running in the second half of 2019. As to PDH, we know that investors -- Enterprise investors are used to projects that are on time or early and virtually never significantly over budget. Clearly, that's not been our experience with PDH. Construction is complete and our engineering and operating teams are now diligently moving through the commissioning phase of the project. Those teams report to Graham Bacon, who heads our engineering and operations. So, I've asked Graham to give you the latest on the startup as of this morning. Graham?

Thanks, Jim. I'll try not to get too deep in the woods -- weeds this morning, but want to outline where we are today. You all know that we released our original contractor and replaced them another contractor, OPD, which is a subsidiary of Koch Industries, in December of 2015. It's always difficult to change contractors in the middle of a project, but OPD started making a difference the first day and we believe we're well ahead of where we would have been without making the change. As Jim said, at this point in time we finished all construction activities and are in full commissioning mode. While we've had some minor issues that have delayed commissioning processes, all utility systems are in service and we've run most of our major rotating equipment in a test type mode. We expect to be introducing propane into the unit within the next 2 weeks and are still expecting to be running and making propylene in the third quarter of this year.

Thanks, Graham. Obviously we're happy about getting this plant online. The startup of this plant is meaningful to EBITDA and DCF and quite frankly, a strategic part of our value chain. Enterprise is working on becoming a fairly major player in niche portions of the petrochemical midstream space. In addition to the iBDH where we already operate one plant and are building the second, the PDH, our legacy propylene splitter activities and our growing export position in propylene; we also recently announced that our petrochemical team is developing a high capacity ethylene storage and transportation hub. As a part of that project, we're converting a cavern in Mont Belvieu to ethylene and adding facilities to increase our receipt and delivery capabilities to provide third-party services to the petrochemical industry.

There are 8 third-party ethylene pipelines within 0.5 mile of our headers in Mont Belvieu providing significant connectivity opportunities for a high capacity system. We are also making progress in developing an ethylene export facility on the Houston Ship Channel. In July we announced that we signed a letter of intent with Navigator Gas to jointly develop an ethylene export terminal. Navigator is the owner of the world's largest combined fleet of indy-size and mid-size liquefied gas carriers, including the largest fleet of ethylene vessels by tonnage. Combine those types of capabilities with our presence in pipeline connectivity and storage, we believe that a relationship between Enterprise and Navigator could be a good fit.

Based just on currently announced projects, the U.S. petrochemical industry will be expanding its ethylene production capacity by 45% between 2016 and 2020 and there are those that expect a second wave. Ethylene storage and logistics, including exports, is a logical extension of what we at Enterprise do well in our other midstream activities. And I'll finish with a few fundamentals. The only thing we can say about oil prices is that while crude oil and products have been stubbornly oversupplied as expected, OPEC recently reaffirmed their commitment to balancing global inventories and indications are their freeze is working. Case and point is U.S. inventories of crude oil and products have drawn 40 million barrels in just the last 4 weeks. Rapid development of U.S. shales has been extremely disruptive to global markets.

But at these lower price levels, it's now clear that high cost and high risk, long lead time projects of the past are simply unable to compete with the short lead time, no risk nature of U.S. shales. We believe the significant increase we have seen in rig counts, which has more than doubled in just the last year, will result in higher levels of production falling into our systems in the second half of this year, 2018 and beyond. We're already seeing a significant volume response to increased producers' activities in the Permian as you would all expect, but also in the Haynesville and we believe the Eagle Ford has turned the corner with its rig count up substantially and we're beginning to see acreage change hands.

While oil and gas prices are weaker than we would like, production in the U.S. continues to increase and demand for hydrocarbons within the U.S. is expanding as major long lead time projects such as crackers, gas-fired power plants and LNG exports ramp up; global markets are quickly calibrating to the growing supplies of U.S. hydrocarbons and petrochemicals. What started with significant new global demand for LPG and then refined products is now moving to new demand for crude oil, ethane, LNG and petrochemicals. Demand across our docks and on the pipelines and terminals that support those docks continue to increase and we believe that the global fundamentals clearly say this is just the beginning of a longer-term trend. Enterprise is well positioned to benefit from the combination of growing U.S. supplies and the domestic and global demand increases that are coming through as hydrocarbons.

With that, I'll turn it over to Bryan.

Thank you, Jim, and good morning, everyone. I will discuss a few income statement items for the second quarter, provide an update on our growth and sustaining capital expenditures for the balance of 2017 and wrap up with an overview of our balance sheet metrics and capital raising activities for the quarter. Before doing so, I'd like to add to Jim's earlier comments regarding our financial performance where we maintained 1.2x DCF coverage during a period, which seasonally experiences lower liquid transportation volumes and was also met by a weaker commodity price environment when compared to the first quarter of 2017 demonstrating again the durability of our integrated business model, which is further complemented by exercising financial discipline.

Now, moving along to income items for the quarter. Net income attributable to limited partners for the second quarter of 2017 was $654 million or $0.30 per unit on a fully diluted basis compared to $559 million or $0.27 per unit on a fully diluted basis for the second quarter of 2016. Net income attributable to limited partners and earnings per unit this quarter included non-cash asset impairment and related charges of $14 million or $0.01 per unit compared to $21 million or again $0.01 per unit for the second quarter of last year. General and administrative expenses were $11 million higher than second quarter 2016 due largely to transaction expenses related to the Azure transaction in the second quarter of 2017, coupled with the benefit of a legal expense reimbursement settlement in second quarter of 2016.

Depreciation, amortization and accretion expenses were $19 million higher when compared to the same quarter of 2016 due to assets being placed into service such as our Morgan's Point ethane export terminal and several crude oil terminal expansions. Provision for income taxes increased $9 million quarter-over-quarter primarily due to changes in accruals for the Texas margin tax. Total capital spending in the second quarter of 2017 was $869 million, including $62 million for sustaining capital expenditures. For the full year of 2017, we currently expect to invest in the range of $2.8 billion to $3 billion for growth capital projects, including the $191 million we paid in connection with the Azure acquisition and approximately $250 million for sustaining capital expenditures.

At June 30, 2017, our total debt principal outstanding was $23.6 billion. The average life of our debt portfolio was 16 years and our effective average cost of debt was 4.6%. Adjusted EBITDA for the 12 months ended June 30, 2017 was $5.4 billion and our consolidated leverage ratio was 4.25x after adjusting debt for the 50% equity treatment ascribed by the rating agencies for the hybrid debt securities and to reduce it further for cash and cash equivalents. Further, when adjusting debt for elevated working capital levels associated with short-term contango opportunities across commodities and contracted growth projects under construction, our adjusted leverage ratio was approximately 4.15x and 3.9x respectively.

For the second quarter of 2017, we retained $145 million of distributable cash flow and raised $308 million in net equity proceeds from our distribution reinvestment program, employee unit purchase program and the at-the-market or ATM program. Similar to last quarter, we had record unaffiliated unitholder participation in our distribution reinvestment program that was paid in May at $90 million in equity proceeds. To that end, I just received the August DRIP participation at a new high of $91 million in equity proceeds. Finally, our consolidated liquidity was approximately $4.1 billion at June 30, 2017, which included available borrowing capacity under our credit facilities and unrestricted cash.

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

Thank you, Bryan. Shelby, we're ready to take questions now from our listeners. And I would like to remind our participants that let's limit our questions to one question and one follow-up question. Thank you. Shelby, go ahead.

(Operator Instructions) And your first question comes from Shneur Gershuni of UBS.

Just a couple of quick questions here at this stage. I was wondering if you can talk about your expected equity needs, I think you just said that you're getting $91 million in proceeds from the DRIP. Do you expect to be issuing equity throughout the balance of this year to fund your CapEx needs or does retained DCF and the DRIP sort of cover everything that you need?

The DRIP goes a long way. That goes a long ways towards our needs for the third quarter. I think if you used history as a guide, you can kind of extract from last quarter we had quite a bit of flexibility, we had limited use of the ATM. I think you can expect that to continue.

Okay. And as a follow-up. I was wondering if you can talk about frac and processing margins, seemed a bit light this quarter. Is if a function of a mix shift? I'm trying to understand sort of the cadence of margins with respect to that segment.

I guess, Shneur, you're asking what do we think processing and frac margins would be on a go-forward basis?

Yes. It seemed like it might have weakened during the second quarter relative to where they were. I'm not sure if it's a function of ramp ups in different areas and so forth. I was just wondering if you can sort of talk about that.

Well, as Bryan mentioned, second quarter is typically seasonally a lower quarter. But as we've seen rallying -- a rally in crude prices, what we're seeing today is increasing processing spreads. So in the second quarter, I can't remember, Tony, we had low $40 crude prices? That always depresses processing margins. Frankly, on frac margins, our fractionators are continually sold out so we're in pretty good shape because most of those are locked in deals and we're beginning to see in the third quarter a little improvement in processing margins. We think you'll see even more improvement as you enter the fall season with LPG inventories not growing as much as they did last year and you're going to start seeing a lot of ethylene plants come online, which should be supportive of the ethane margin.

And your next question comes from Brian Zarahn of Mizuho.

Staying on the NGL segment, any color on the second quarter volumes on MAPL and Seminole? South Texas is understandable, but simply how much of an impact or what's taking and what's happening in MAPL and Seminole and is that changing at all in the third quarter?

We just named Tug Hanley as running that regulated business. So, let's see if he's on top of his game.

I will give it a shot. So on our Rocky system, we're continuing to see some lower volumes come in. But one of the nice things about our integrated assets is we're also seeing a pickup in the Permian. So, we're seeing some of our downstream assets from Rockies, maybe Seminole and Chaparral. So, we're starting to see those volumes pick up.

And let's address the Rockies, one of the things we've seen -- that we see in developing the Rockies. First of all, we've done some deals at our Pioneer plant. That plant is going to be full built in the next 10 years. And then we've seen EnCana -- you know a lot of these basins and it's what happened in the Haynesville is you had acreage turnover. We've seen volumes in the Haynesville go Northeast. Now you've seen EnCana sell their Piceance position and we know the people that bought them and they have intentions to put rigs out there. So, we expect our Meeker plant to start ramping up over the next couple of years. So, we think what's coming out of the Rockies is going to increase and I said earlier, we're not through in the Delaware Basin and you'll see more plant announcements if Brad Motal is doing his job in the Delaware Basin. The other thing on a go-forward basis is you should see with -- with new cracker demand, I could see more ethane rejections subsiding. So, you know it kind of looks a little brighter than it looked in the second quarter in the future.

Brian, and just a little bit more context. When you compare second quarter of this year to second quarter of last year, volumes on Mid-America and Seminole are flat. Sequentially volumes are down, a lot of that is just seasonality of weather but then also you're also going to have pipe being down for regular maintenance in second quarter, third quarter. So typically Mid-America, Seminole volumes are going to be all second quarter, third quarter.

I guess shifting to the Permian, any updated thoughts. Just building off of Jim's recent comments on processing plants as well as your -- the competitive landscape for Shin Oak and then any update on the gas pipe that you're evaluating?

On Shin Oak, I'll put all the burden on Brad Motal. I think you're going to see - and Bill you can help on this. We don't think we're through in the Delaware and you heard what we just said as it relates to the Rockies. The most reliable supply you can have for a pipeline or a fractionator is supply that comes out of your own plants. As we grow those plants, we think our competitive position is enhanced and we believe that we're well positioned given -- I know, Brian, y'all hear it all the time, but that value chain approach works. So given -- and we will look at -- we look at bundled services. Our competitive advantage is not Shin Oak in and of itself. Our competitive advantage is the total system and we're not afraid of it at all. Do you want to add to that, Bill?

No, I think what Jim said is we've announced the 2 plants at Orla. They're both under construction, scheduled to come on second quarter and third quarter, fourth quarter next year. And Brad and his folks are actively pursuing what could eventually relate to 2 more similar trains in that area. So I don't think we're finished, as Jim said, and continuing to move ahead.

On the gas pipe, any update?

Yes, we're still working it. Do you want to comment on that, Bill?

I think Brad's still working it. We've had a number of folks come to us talking about the potential of a joint venture or something. We're listening. I don't think we're ready to make any announcements at this point in time. It's tough to make money on those gas pipes because we have to see what the spread does and how it goes. But given the fact that we're seeing a lot of gas coming out of the Permian and the fact that most of that gas is associated gas and the producers are starting to see a little bit more of it is as you guys are aware, we think there's going to be a need for a pipe and the question is who's going be able to pull it together and pull the commitments together and where's that pipe going to go. So, we're continuing to work on it, but I don't think we're ready to take any victory laps at this point in time.

And your next question comes from Yves Siegel of Neuberger Berman.

Yves, you there?

Can you guys hear me? So the first question is maybe Jim, you were talking about the crude and producers' outlook for controlling the crude. Can you just frame the argument with Corpus Christi and the Houston Ship Channel and how does that fit into the equation as it relates to congestion in the Houston Ship Channel versus Corpus Christi? Where do producers want to go and are there problems with the Houston Ship Channel given congestion concerns?

Some guy -- there's a famous guy in Washington D.C. that would call that fake news. You look at what producers want. They want to make sure that their product flows and they want market choices. So if you compare, and I'm doing this off the top of my head from a slide that Tony put together on this subject, but just you look at markets, you don't look at docks. So if I'm going to the Houston Ship Channel, I got a market that's up on the upper Texas Gulf Coast that's fully connected to the Houston Ship Channel by pipe for 4.5 million barrels a day of refining; if I'm in Corpus, I got maybe 800,000. If I'm going to Houston, I'm looking at 300 million barrels of storage; if I'm going to Corpus, I'm looking at 20 million. If I'm going to Houston and we talk about congestion, congestion is a matter of parking places. If I'm going to Houston, there's 150 docks; if I'm going to Corpus, there's 20. So if I want my product to -- the other thing that producers are demanding and Brent says it right, quality is king. They want segregations and they want to control their own barrels. A lot of these guys have already been out kicking tires in the global markets and they're beginning to understand what those customers want and they want to be in control of their own destiny. So when you're in Houston, you're not captive to a limited market, you've got multiple outlets and rather than looking at whether a dock can hold a VLCC, they are looking at what's the market opportunities and the export capability is a component, but not the total. So, you can tell I get a little wired on this subject, Yves.

Well, if I could just shift gears just a little bit. Philosophically how do you think about JVs and there I'm thinking about Shin Oak potential JV, number 1? And number 2, and this may sound a little bit silly, but there's always the concern that the industry's going to overbuild and to a certain extent maybe doing JVs prevents some of that from happening in the future. So, maybe you can expand on the prospects for a JV with Shin Oak and just philosophically how you think about it?

I'm not going to talk about Shin Oak specifically, but I will talk about the philosophy. The philosophy at Enterprise is if you think about it, Dan built this company with joint ventures. We got joint ventures in our PP splitters, we got joint ventures in our fractionators, we have got more joint ventures in Louisiana than we can count. So, joint ventures are something that we are always open to. The thing that -- the criteria is pretty simple though. We don't want your money, we either what you to bring product in or we want you to have an offtake. For instance, we got a fractionator in Louisiana that we joint venture with a petrochemical company. So, we're wide open to joint ventures. And I think we've said in the past, I think Randy has and Bryan have said in all these conferences they go to that we would be open to a joint venture on Shin Oak. But we're not afraid to -- it's not something that we're going to -- we're going to build this pipeline and it's going to be pretty strategic to us.

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

How hard is it to add LPG export capacity? Are expansions of existing capacity far cheaper than the initial buildout was?

People think about LPG export capacity and they think I'm going to put a dock in and I'm going to buy my propane. It's not that simple. You really need the ability to produce export quality LPG. For example, propane, Graham, is 2%, 2.5% ethane while domestic is 6% ethane? So, you got to have all the infrastructure that supports that so it's not easy. And you can -- to expand it, you've got to expand your capability to produce export quality propane or butane and you've got to expand your refrigeration and you probably got to add pumps to increase your loading rate and you better have high capacity storage and that can either be adding fully refrigerated above ground storage or adding the capability to turn a salt dome cavern into a higher capacity one. All that said, it's a lot easier to add -- it's easy to add more capacity.

Okay. So, would it be fair to say that that those with the capabilities now and the capacity now to export out of the Gulf are kind of the set of players? It's pretty hard to imagine new people coming and building a bunch of new LPG export capacity in the next few years.

Well, you're not going to see me leave Enterprise and try to go into that business by myself.

That's helpful. And then I just want to make sure I understand the ethylene export terminal. So, it would be the same ships that could then switch to exporting ethane. Is your view that probably for the first couple of years it would be ethylene and then maybe you would just start doing more ethane as a share of ships, as demand rises for that going forward from there?

You know that is a scenario. But the way I look at this is a lot of these new ethylene plants and the derivative plants, and Tony correct me if I mess up or R.B. A lot of these -- most of these -- a lot of that product they are going to be exporting is polyethylene. To me, if I were a big producer of ethylene, it's a fairly cheap option. If I can't place my polyethylene to have the ability to load ethylene in order to keep my plants running at rates that I want them to run at. So I think that -- I think you will see and I think R.B. can bear this up is if we are successful in this, we're going to have merchant players who want this because they need it, but you're going to have integrated petrochemical companies who want this as an option to their ability to export polyethylene.

That's really helpful and that's all from me. Thank you very much.

Your next question comes from Jeremy Tonet of JPMorgan.

Just want to circle back on ethane a bit more here. It seems like prices popped up a bit recently and was just wondering if you guys could share with us how much rejection you kind of see across the U.S. right now and if ethane rejection is starting to subside a bit more, the impact on your pipelines and just kind of how you see that playing out. We talked a good amount about the demand increasing, which is encouraging to see that.

I think I'll take it. We don't model it day in and day out how much even that we believe has been rejected, but it's going to move with those spreads -- with the ethane to gas spreads so natural gas impacts it also. Regionally natural gas impacts it, it should be just like it is or should be movement in this market. So, I don't want to say that there's been a sea change one way or another yet. We still are rejecting a significant amount of ethane and those volumes are going to move with the whims of the market including the gas market by region.

It's all about demand, but the other thing it's about is the gas to crude spread. And as these ethylene plants come on -- frankly I think you'd have more ethane rejection than you have and you got a lot, but a lot of these guys or producers have commitments so their variable cost is zero. So, they may be extracting ethane basically to mitigate stranded capacity. And then if you look at Enterprise, if we own the pipe, then we're going to operate around our variable economics. We don't have to have a spread that justifies the total.

And then just want to circle back to the crude oil segment and it seems like the marketing kind of ticked up there a bit and wanted to see if differentials were getting better or anything else that you could expand upon as far as driving the strength this past quarter?

Brent, you got a clue?

It's not necessarily one specific strategy. We had some decent spreads across our docks, some of the prices have gotten healthier in terms of our Gulf Coast markets, but it's not necessarily just one specific strategy. There's starting to be some spreads you're seeing between Midland and Cushing that helps. And then once our pipeline comes online from Midland to Houston, then that will help us as well.

Are you seeing spreads where you're exporting more?

In terms of exports, August will be a record month for marketing segment for crude oil. I imagine as crude Enterprise marketing goes, the industry goes. So, we definitely see an uptick on volumes of crude oil across our docks in August. We're having record volumes across our docks on refined products. And I don't want to speak for R.B., but I'm going to make the assumption we're having the record volumes for petrochemicals as well.

So if you strip out the mark-to-market noise, is this kind of a new baseline that should grow as Permian production increases?

What's the appetite for WTI?

So when you talk about WTI in terms of I'll call that the Midland Permian barrel not the Cushing DSW barrel, there is a healthy appetite for WTI both in the Houston Gulf Coast market and then also across our docks in the global market. So, I'm not worried about selling it. The question is where are we going to sell it? Are we going to sell it domestically to the Houston market? At some point market, that market will be saturated and we've said this in the past that barrel will clear across the water. But in terms of who we talk to in the global market, everybody is focused on it, everybody is trying to position themselves to take that barrel from the Houston market.

And your next question comes from Matthew Phillips of Guggenheim.

A follow-up on the crude segment here. You're at 83% you said for the -- the Midland-to-Sealy line. I think it's kind of been at that level for a quarter or 2 now. I mean are you saving the incremental capacity for walk-up or what is kind of the producer outlook in terms of putting more barrels on that system?

I think we're going to be -- we say in our notes 405,000 barrels a day. I guess the idea is that the balances for walk-up capacity are hopefully Brent's primary walk-up customer. But we are not going to be at 83% when the pipe comes up, we're going to be at a higher percentage than that. And hang on just a bit. And you say we've been there for a while. I think we announced this past quarter that we just signed up and did we say how much that volume was? Basically we signed up another 100,000 barrels a day. So, it may have been there for a while if you call month a while.

Yes, I thought it was from last quarter, but I could be wrong there. And then on the fractionation side, what drove the sequential increase in volumes there? Was that just ethane recovery or was there something else going on?

Say that again, I'm sorry.

This is Brent talking. At the end of the day, our frac capacity has not increased. So if our frac volumes went up, either it had to do with some sort of maintenance that we were doing in the prior quarter or it has to do with ethane -- the stream having more ethane in it.

We've also had volumes ramping up in our 2 new plants out in the Delaware, the Delaware Basin plant and the South Eddy plant. And with the purchase of the Pascagoula plant interest from BP, we've got additional volumes coming into our system that weren't coming into our system before that purchase too. So, that may have some impact on it.

Your next question comes from Darren Horowitz of Raymond James.

Jim, I want to go back to your comment on the opportunities across the petrochemical value chain for a minute, and I noticed that in your latest slide deck that you've got a chart showing really low U.S. propylene inventories and obviously one could imply from that that you'd be advantaged to have access to some low cost propane especially when the seasonal demand for propylene increases and also what could be a growing arbitrage between, let's just say, normal butane and maybe butylene and isobutylene or some other derivative. So, how do you see for you and your book that opportunity developing into the end of this year and what more can you do to capitalize on that?

What have you been doing? You've been reading Chemical for Dummies?

I've been trying to steal Brent's playbook.

I think -- Darren, I think it's pretty obvious that when we look at extending the value chain -- Enterprise has always been in petrochemicals. The first tower that Dan built out there was a propylene splitter out in Mont Belvieu. So, we've always been in petrochemicals. We see -- we like the idea of moving further downstream. So, I really like -- if R.B. can pull it off, I really like the idea of building an ethylene storage, logistics and potentially export system. It's our way to be in the ethylene business without going full hog. So iBDH, we love the isobutylene, it's an extension of C4s; PDH, it's an extension at C3s and we see this as our way of extending our C2 value chain. I don't know if that answers your question. But the point is yes, we're focused on going further downstream.

I think that makes sense. And then for my follow up, more of a housekeeping question. And Bryan, I apologize if I missed it, but what's the amount of debt currently or I should say capital currently allocated on that working cap facility for as you said those core short-term contango opportunities?

It's right around $800 million and typically we're right around $300 million.

Okay. And I would expect that to increase, is that fair?

Well, it kind of depends on what happens with the market. So that's the thing is that it certainly has gone longer than traditionally, but we've kind of been in a slow recovering market here. So, hard to say -- to project out as far as how it will move.

This is Brent talking. I would say look at the forward markets and what we do contango on and that will probably give you answer.

And your next question comes from T.J. Schultz of RBC Capital Markets.

First on PDH, just 2 parts to the question I guess. What type of ramp should we be expecting over the next few quarters as it starts up? And then second, where does litigation with the original PDH contractor stand right now?

Let's go the second one first. Hap or Vijay, you want to answer it? You don't want me answering that question.

The case has been filed and is progressing through the discovery phase right now.

That's about all you're going to get from a lawyer, T.J.

No pressure on that litigation that should we be expecting. And then what about the ramp on PDH as it starts up?

As far as the ramp-up, we expect a little bit of a shakedown in the fourth quarter and really fully up and operational at full rates in the first quarter of next year.

And T.J., you know he's going get one hell of a lot of pressure on that.

Yes, understood. I guess a last question from me would just be on the structure. You guys have studied the up-C structure and then you've made comments about kind of checking the box to be taxed as a C Corp as really a limited taxable event and all this depends on your view of access to capital in the MLP market. But just as you think about the project backlog over the next couple of years and funding needs, what's the current thinking on access to capital as it relates to your structure right now?

T.J., this is Randy. I mean we continue to come in and evaluate structure and form, but really no new developments on that front. I think as far as access to capital and if you would, the projects that we currently have under construction, we feel like we've got good access and good cost of capital. So, we're pretty content with where we are.

Your next question comes from Michael Blum of Wells Fargo Securities.

Can you remind us again, just your -- the latest in terms of your thinking on how as the ethane export dock ramps up, how that's going to sequence versus capacity and actual volumes over the next whatever year, 2 years?

Some of these guys are still finalizing their facilities, which probably is going to create some deficiencies I would think, where is Justin, some time in this first phase. But I think we -- I don't even remember what the ramp is. Do you, Justin? I guess it's mid next year before we're fully loaded.

Yes, it should be mid next year. I'd say volumes that we've published across the dock here aren't necessarily reflective of where we are contractually. So, we're still behind on the contractual versus physical side, but we expect that to increase as we get to the next 12 months.

Okay. And then maybe just turning to the Northeast for a minute, any updated progress on Centennial and just maybe within the context of that, just your latest thoughts on kind of the supply-demand dynamics for Northeast NGL markets? Thanks.

This is Bill. As far as Centennial goes, we just were not able to pull the interest together that we would need to do a project of that magnitude at this point in time. I won't say we've totally given up on it. We will continue to keep our pulse on it. But at this point in time, we just haven't been able to pull together the interest in that project.

Your next question comes from Keith Stanley of Wolfe Research.

You guys have talked some about growing Asian demand for LPG, just curious if you have any updates on contracting efforts for LPG exports or are you seeing a lot of interest in extending contracts and are you actively working on that or comfortable waiting a couple years?

We're not comfortable waiting on anything, I'm about as impatient as they come. But what we're seeing is I believe is growing demand and funny you should ask. I just got back yesterday morning from Asia. These guys are reaching the point where they're fairly dependent on U.S. export. Strategically if you look at it as they put their portfolios together, what would be the price out of the AG if it weren't for U.S. exports?. And yes, we're constantly working to extend contracts. I'm not so naive that I think those contracts are going to be extended at $0.12, $0.14 a gallon, but they are going to be extended and there is an appetite for them.

Okay. And just one follow-up. Just any latest thoughts on M&A and just are you more optimistic you'll find sort of smaller tuck-in type acquisitions like Azure? Do you think that there will be sizable opportunities as well as over the next year or so?

We don't have a -- we constantly look out. I'll let Randy chip in in a minute. But we look at a lot of things, but we're pretty disciplined. We're not going to go buy something just to say we are buying something. We'd rather build, we'd get a better return on that and I'm not going to tell you that we don't constantly look. But when you look back, I think the largest acquisition we've ever made was the Oiltanking acquisition at $6 billion. So yes, we will continue to look. If things like Azure comes on, we'll jump on them, but it's not like we need them to grow. You got anything?

Your next question comes from Nick Raza of Citi.

In terms of the walk-up volumes on ATEX, is there an opportunity perhaps to firm some of those up?

It's kind of a timely question because I didn't hear you because Randy and I were talking about the Northeast. People -- there are producers who seem to think we've got a lot of easy-to-add capacity and that's not true. I think our capacity on ATEX will top out, Bill or Tug, at 144, 145. Beyond that, it's pretty darn expensive. So, I was a little surprised -- well, I wasn't surprised, but somebody asked earlier about Centennial, I think these guys are going to be challenged on takeaway in particular on NGLs. But I understand because a lot of them have so much stranded capacity on natural gas pipelines. I mean it's hard to make a 10-year commitment and on the money we're talking about on Centennial, we're not going to do that without the kind of commitments that will support the size of the investment. You got anything to add?

The only other comment and again, this follows back up on Michael Blum's question earlier, is out of the Northeast from an NGL perspective, there's a limited number of outlets and what we're seeing if you have a ripple due to maintenance on one of those outlets, just like what we're seeing this month in the month of August on ATEX, we're going be at record volumes on ATEX because of pipeline maintenance on other facilities. So, sort of still limited outlets.

The other thing is when you talk about firming up walk-up capacity, we really can't. I mean all the movements through ATEX are FERC regulated movements and FERC requires that we hold 10% of the capacity related to those movements back for walk-up capacity. So we can use it, others can use it, but there's really no mechanism out there where we'll be able to firm it up.

Okay. That's very helpful. And then just turning really quick to Orla. You mentioned you may have more projects in the backlog and essentially more expansions. I think you said there could be 2 more. But at what point do you think you could have enough of critical mass to actually do the pipeline, in particular your natural gas takeaway pipeline? Is it after the ones that you already have in execution come online or do you have to announce more projects before you have enough volume aggregated to actually make a project viable?

From those plants, we've already got a natural gas takeaway pipeline that's going to be built down in Waha. So, I don't know that we're talking about building a natural gas takeaway pipeline specifically for those plants. I think what we've been talking about is a pipeline linking the Waha market to the Gulf Coast.

So I mean essentially if you control the molecules say of -- you control the molecules into Waha, you could conceivably control the molecules downstream. I guess the question is really just how much volume can you sort of aggregate at which point in time you can actually have a pipeline system or a viable opportunity to make a pipeline system down to the Agua Dulce?

This is Brad. As part -- as a follow-up to what Bill said, technically we don't control those molecules. So, we're just getting them to Waha at this point. What I can tell you is our growth on the gathering and processing piece, it helps support it, but I would say you're still, as Bill said, looking to leave Waha which effectively means you need to aggregate volumes outside of the volumes that leave our gas plants to create a project that's viable in the competitive market as it is for this kind of pipeline.

We tend to aggregate and control much more on the NGL side out of those plants than we do on the gas side out of those plants. The producers tend to like to hold on to their gas.

Your next question comes from Rebecca Followill of U.S. Capital Advisors.

One of the more recent themes we're hearing out of E&Ps this quarter is higher gas oil ratio out of the Permian with -- with not necessarily lower oil production, but more gas and liquids per barrel and some discussion of upsizing plants as a result. Beyond the normal course of business with your customers, have you had any discussions on this?

No, not really. But higher GORs with the same amount of oil results in more gas that needs to be moved and more NGLs that are going to be produced and need to be moved so we're going to obviously keep our finger on the pulse there. First we really started hearing of that was in the last couple of days so we're going to be talking to those producers and trying to understand it a little bit better.

Your next question comes from Barrett Blaschke of MUFG Securities.

A lot of mine have been answered, but I did want to ask a little bit about not necessarily round 1 of petrochemical crackers, but the growing round 2 of crackers and your outlook there and where you see those developing.

I'm going to let Tony take a shot at that because he believes in a second wave. I'm just looking forward to the first wave getting here.

So given what the U.S. has from a supply situation, we are -- we are talking to a significant amount of people that appear to have an interest in continuing to build on the U.S. Gulf Coast incremental ethylene capacity. So, I firmly believe that there will be a second wave call it in the early 2020s. Obviously I can't talk about who that is or I couldn't even speculate which ones will go through. But many of the people we're talking to, just like you see today on the ethylene crackers, are foreign players that want exposure to U.S. NGLs.

Okay. And just a quick follow-up and that is I think we're all very aware of what -- what the risk picture looks like as midstream players go closer to the wellhead. You guys are obviously doing more going downstream and going further away. Could you give us a little bit of color around sort of what the different risks are as we move in that direction versus towards the wellhead.

What we're doing costs more money and it's harder to duplicate, pure and simple. We think that from a -- Brent, may want to chime in on this. But the easiest thing to do is build a gathering system and get a dedication and call yourself a midstream company. What we're seeing is producers, and we'll use the Permian as an example. The producer is going to dictate what that gatherer does for him and he's going to dictate whether or not he wants -- what kind of segregations he wants. So, we're going to build this pipeline up and we will build out into certain basins. We will do things like buying the Eagle Ford system from Pioneer. But our focus is we like things that are -- that have a high barrier to entry and we like things that add to our downstream value chain. Brent?

That's exactly it. I mean I think upstream of hub markets is incredibly competitive and at some point, you step out of that arena and so I think we'll pick and choose as Jim said. But usually when we choose, it's when a larger producer wants us to control those barrels all the way to where they want to go and that's either going to be in the Gulf Coast refinery market or across our docks and they want one midstream provider to handle that barrel without having anybody else touch it. So, that's probably when you see us step out somewhere and that will be to lead.

And I think the same holds true in the gas and the NGL side of the business.

Shelby, is that all of our callers?

There are no further questions.

Included in the email from Pam Bricker this morning was the replay information for our call today. It will be good, Shelby, if you just repeat it for our listeners and then that will end the call.

This call will be available for replay beginning at 1 o'clock PM Eastern Time today through 11:59 PM Eastern Time on August 10, 2017. The conference ID number for the replay is 49822181. The number to dial for the replay is 1-855-859-2056 or 404-537-3406.

Thank you, Shelby. And that ends our call today and thank you for joining us and have a good day.

This concludes today's conference call. You may now disconnect.