Enterprise Products Partners LP (EPD) 2016 Q3 法說會逐字稿

Good morning. My name is Jennifer and I will be a conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners third-quarter 2016 earnings call.

All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you.

I would now like to turn the call over to Mr. Randy Burkhalter. Sir, you may begin.

Thank you Jennifer. Good morning, everyone, and welcome to the Enterprise Products Partners third-quarter 2016 earnings call. Our speakers today will be Jim Teague, Chief Executive Officer of Enterprise's 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 may 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, they 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.

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

Thank you Randy.

For the third quarter of 2016, Enterprise generated $1 billion in distributive of cash flow. Our distributable cash flow was reduced by approximately $33 million because of pre-commissioning fees for a PDH plant and ethane export terminal, and estimated expenses and loss revenues at our Pascagoula gas processing plant, which is expected to be up in the fourth quarter. We increased our distribution by 5.2% during the quarter and retained $124 million of distributable cash flow. Year-to-date, we have retained over $550 million of cash to reinvest in the business.

For the quarter, we transported over 5 million barrels a day through our liquids pipelines and handled over 1.2 million barrels a day of liquids at our marine terminals. Our volumes were hurt somewhat by weak ethane recoveries industry-wide, lower volumes on our Eagle Ford crude oil pipelines, and downtime and repairs at our Pascagoula natural gas processing plant. Increases in gross operating margin for many of our fee-based businesses partially offset these lower volumes.

While some things like ethane economics are beyond our control and did impact our volumes, we continue to be very aggressive in keeping volumes moving through our system. The third quarter is typically our weakest, but our people, using our integrated system, continued to perform at what are still tough market conditions.

Signs continue to point to improved fundamentals. Crude oil prices have nearly doubled since February. The US oil rig count is up over 125, or 40%, since May. There are signs that global inventories will balance in the second half of next year. And there appears to be discussion by OPEC to freeze their output.

Since August, ethane has gone from $0.16 to $0.25 a gallon, propane from $0.40 to $0.60, butane from $0.60 to $0.80, and natural gasoline from $0.90 to $1.20. The value of an NGL barrel in south Texas has gone from $0.40 in early August to over $0.55 today. While the move up in oil from the mid $20s in February has been impressive, there has also been improvement in natural gas prices where the calendar strip for 2017 has gone from $2.50 to over $3.00 since March. These types of oil, gas, and NGL prices put a lot of basins in the US in the black, and have given US producers the ability to hedge 2017 drilling programs.

As to projects in September, we placed our ethane export terminal in service at Morgan's Point. Projects like this truly are exciting, and we're extremely proud our people were able to complete a world scale project of this size on time and under budget.

We also announced that we added propylene export capabilities to our Houston Ship Channel facility. After we complete our PDH plant early next year, Enterprise will have the capability to produce 9.5 billion pounds per year of propylene, and we fully expect that Enterprise will play an increasing role in the global propylene trade.

During the third quarter, we began service at our Delaware Basin gas processing facility where volumes are currently ramping. This plant is owned 50-50 with OXY. We also built an NGL takeaway line from the plant that connects to our Chaparral pipeline, and given our focus on value chain, moves the liquids to our Mont Belvieu facilities. Our Texas intra-state gas pipeline is providing the natural gas takeaway at the tailgate of the plant. This is the second major plant we placed into service in the Delaware Basin this year. We've started construction on our third plant in the Permian, a 300,000 MCF a day plant in the Delaware basin, supported by long-term contracts with major producers with startup projected to be in the second quarter of 2018.

We are not finished adding assets to serve this basin. All in, we have $5.6 billion of projects under construction and we have several major projects under development, some that we hope to announce before year-end.

You can't ignore what's been happening in our industry over the last six months. The announcement around the potential OPEC production freeze is certainly encouraging, but we've had very positive momentum since March that had nothing to do with the freeze.

At Enterprise, we really don't focus on OPEC -- what OPEC does. We focus on what we do.

Global demand continues to increase by over 1 million barrels a day per year, and US producers continue to reduce their costs of finding and producing while frankly weaker-producing nations are struggling to compete.

The reality is that while it feels like bad news comes all at once, the path to recovery is never smooth. We are optimistic, but we are also realistic. We believe that we are at the inflection point of a recovery phase. It won't be fast; it will be volatile. However, at Enterprise, we have never feared volatility. We embrace it.

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

Thank you Jim. I will discuss a few notable income items for the third quarter, provide an update on our growth and sustaining capital spending during the quarter, along with expectations for the remainder of the year, and close with an overview of our balance sheet metrics and capital raising activities for the quarter.

Net income attributable to Limited Partners for the third quarter of 2016 was $635 million, or $0.30 per unit on a fully diluted basis, compared to $649 million, or $0.32 per unit on a fully diluted basis, for the third quarter of 2015.

Asset impairment charges were $7 million for the third quarter of 2016, which is a $20 million decrease when compared to the same period in 2015. We recognized a $9 million gain from the sale of our Reno and Rockland propane terminals in the third quarter of 2016, versus a $13 million loss taken from the disposition of our offshore business in the third quarter of 2015.

G&A expenses decreased $7 million this quarter, primarily due to lower compensation and legal expenses.

Total capital spending in the third quarter of 2016 was $621 million, which included $62 million for sustaining capital expenditures. We expect organic growth capital expenditures for 2016 to be approximately $2.8 billion and sustaining capital expenditures to come in around $250 million this year.

It should be noted the $1 billion second and final installment payment for the EFS Midstream assets made in July of 2016 is excluded from the aforementioned capital spending figures.

At September 30, 2016, our total debt principal outstanding was $24.2 billion. The average life of our debt portfolio was 16.2 years, and our effective average cost of debt was 4.5%.

Adjusted EBITDA for the 12 months ended September 30, 2016 was $5.2 billion and our consolidated leverage ratio was slightly under 4.5 times after adjusting debt for the 50% equity treatment ascribed by the rating agencies for the hybrid debt securities and to further reduce it for cash and cash equivalents. This peak level of leverage is consistent with the guidance we've provided during the last several earnings conference calls as well as the peak metrics we presented to the rating agencies at the beginning of the year during our regularly scheduled annual review.

An important item to note and was referenced in last quarter's earnings call is that we had approximately $1 billion of incremental debt or an incremental 0.2 times of leverage. This is associated with working capital tied to marketing opportunities across commodities that are scheduled to liquidate over the fourth quarter of 2016 and the first quarter of 2017.

Further, we anticipate modestly lower leverage metrics over the next several quarters as late stage growth projects come into service, the aforementioned short-term marketing inventory positions liquidate, and an increasing contribution from completed projects with a contractual ramp in cash flows, such as but not limited to our ethane export facility, our Aegis pipeline, our EFS Midstream assets, and our ATEX pipeline.

Our disciplined approach towards appropriately managing leverage over the long-term has not changed where we continue to target leverage metrics of 3.5 to 4 times. Our leverage metrics remain in this range when adjusting for debt associated with growth projects under construction and applying their proportional contracted cash flow.

In addition to the $124 million of retained distributable cash flow during the third quarter, we raised $282 million in net equity proceeds through our distribution reinvestment program, our employee unit purchase program, and the at-the-market or ATM program.

As mentioned earlier in the year, we largely pre-funded the majority of our 2016 equity needs during the first four months of 2016. As a result and similar to my earlier comments on leverage and Jim's comments regarding an improving commodity price environment, DCF coverage is typically at its lowest level during the seasonally weaker third quarter and should improve over the next few quarters.

Finally, our consolidated liquidity was approximately $3.5 billion at September 30, 2016, which included available borrowing capacity under our credit facilities and unrestricted cash.

I will now turn the call back over to Randy.

Thank you Bryan. Jennifer, we are ready to take questions from our audience.

(Operator Instructions). Brian Zarahn, Mizuho.

Given the recent uptake in rig count activity in the Permian, any high-level views of the impact to your asset base and any potential updates on the Midland-to-Sealy pipe?

I think the fact that we are starting construction on our third plant out there and the fact that in my comments I said we're not through obviously what's going on, we are paying close attention to it, and we are pretty excited about it. As to our Midland Houston pipeline, granted the pipe is purchased, the right-of-way is all but done, over 90% of the right-of-way, I think we are looking at April, May of 2018 we're going to build the pipe, and we think it will be full. Its initial capacity is 300,000 barrels a day. And Laurie, we've got one, two, three contracts.

Yes.

So, it's going to be a success. I think it's a project we needed and it's a project that, before it's all said and done, we're going to expand.

On the crude pipe, any -- this incremental more interest in signing up capacity or is it still under discussion?

Say that again, Brian. I'm sorry.

I think your last update was about 60% of the pipe was contracted. I guess any updates or any color on conversations with shippers given the crude price recovery, the rig count activity, M&A activity in the basin.

Yes, we are having more discussions on that pipe, and it's not going to surprise me if we are full when it comes up.

Okay. And then I guess my second question would be any broad strokes on some of the projects you're looking at, any update on Centennial?

We are pretty excited about the projects that I mentioned. We have a handful that -- you know, when crude prices are in the $20s and gas prices are $2.00, organic projects gaining traction is kind of difficult. What we've seen is we've got a handful of projects that we are working on that are very exciting, and I think we'll pull at least a couple of them, if not three of them, across the finish line, and certainly Centennial could be one of those.

Do you think Centennial will be one of those by the end of the year that could be announced?

Keep trying, Brian.

I know you're cracking the whip, Jim, I don't doubt that.

Brian Gamble, Simmons & Company.

That enthusiastic chuckle was a great little reprieve, Jim, I'm sure you are doing a great job.

The question I wanted to focus on was on the NGL market. You talked about the ethane economics and how it's impacted volumes. Clearly, there is still a pretty decent slate of crackers scheduled to come online by the end of 2017. But Jim, can you walk us through anything that's changed in your mind or, from a timing standpoint of balancing out that market as economics have been shifting? Clearly, they have been very volatile and you noted the uptick since August. But when you look longer-term, maybe a few just opinions and broad strokes about where you see the industry, and any changes that have developed in your mind over the past months or quarters.

When you have this much capacity come on, things happen. If you listen to Tony, and I do, and these crackers come on and they run at rates, then you've got an appetite for ethane that cannot be supplied -- satisfied on the Gulf Coast. So, it's got to attract volume from other places like the Northeast or out of the Rockies or out of the Mid-Continent. If you are sitting in the Permian or the Eagle Ford, you are probably in pretty good shape from a margin perspective. However, if those crackers come on and their ethylene margins compress and they don't run at the rates we expect them to, then the appetite will be less. Ultimately, they will run, and they will attract ethane barrels from the Northeast and from the Rockies. But it really doesn't hurt their competitiveness when you think about it, because it's still about the gas-to-crude spread. So you can have ethane prices go up so that it supports transport out of the Northeast or the Rockies and then ethylene plants still be advantaged here relative to the rest of the world. I'll ask Tony if he wants to add to that.

I've got nothing to add. Thank you.

Great. And then my follow up, I guess the best place to just focus on that particular point when you guys mentioned your ethane export levels for Q3, you note the year-end 2016 and year-end 2017 levels as well. Can you remind us of, A, how much additional capacity there is beyond those quoted rates, and then B, what sort of EBITDA impact that could be by the end of next year?

I don't have the EBITDA impact, but Joseph, we've got about 25,000, 30,000 barrels a day of additional capacity to sell?

That's correct. The total capacity is 200,000 barrels a day.

We are at about 165,000, 170,000, in that range?

We are probably around 175,000.

175,000. And I don't know, pick a number, $0.10, $0.09 a gallon? I screwed up your negotiation on your next deal.

Pick a number.

We say -- when Joseph says our capacity is 200,000 barrels a day, that's what we feel like our operational capacity is. Our instantaneous capacity is 10,000 barrels an hour, or 240,000 barrels a day.

To be fair, we are going to be a little conservative in what we contract to until we get some experience under our belt. But if the ethane facility is anything like our LPG facility, we will run that thing at over 90% operating rate. And in my background, I always thought 80% was fully utilized. Here we go over 90%, and if we do that on ethane, then we've got more to sell.

Great. Thanks Jim.

Brandon Blossman, Tudor, Pickering, Holt.

Good morning everyone. Someone is going to have to ask this question, Jim, so I'll be that person. M&A thoughts as you sit currently, kind of balance of strategy versus valuation? If something came in the door, what would you rank, one over the other? And is there anything missing from your portfolio today as you look out over the next five years that you would like to add just from a commodity or a business line?

I think Randa --

I have more if that's not enough.

Yes, Randa whispered in my ear that the answer to your question is yes. I think we may as well look at the elephant in the room. We had some discussions along the lines of Williams, and obviously one of the things that we liked about that were their long-haul natural gas pipelines. Personally, I don't think you build your way into that, but if that was something that came available, we would probably look at it.

But I think people -- we made some acquisitions recently, and I think folks -- we are looking at things almost every day from little to big. But one of the things that excites us right now is seeing more organic projects that have darn good returns that we are in control of from the get-go. And while acquisitions could make sense, price matters, and we are not going to chase them.

That is a comforting answer, I think. Easier -- a much easier question, Midland-to-Sealy, 24-inch pipe, current capacity 300,000. You've talked about being able to go up to 450,000. The question is, is that the absolute capacity, 450,000? And what would CapEx requirements be to move up higher than that?

That's pretty much the absolute capacity, isn't it Laurie, 450,000? I don't know what the CapEx requirements are, and I doubt I would tell you if I did.

Just order of magnitude, relatively minor?

It's nothing much. It's incremental, and it's pumps.

Okay, as expected. And then just real quick, in the prepared comments or actually in the news release, some comments around Eagle Ford and Haynesville, signs of life. Any incremental color on that that you can provide?

This is Tony. Let's start with the Haynesville. We are seeing a significant change in operators, new operators coming in, acreage being sold, applying new science -- I shouldn't say new science, applying science that has not been applied in that acreage. And the results that we are seeing generally are exceeding even what the new producers told us they were going to do. So they are very happy with their results.

Relative to the Eagle Ford, the Eagle Ford acreage is largely held by production. You have I'm going to call it a handful of major players down there that largely are not drilling because their acreage is held and they have an interest in holding acreage in other areas. But when we -- so we think some of that acreage is going to change hands just like we've seen starting in Haynesville, except the deals are going to be larger.

We feel very good about the Eagle Ford rock, as we always have. It's now developed at what we believe is a commercial lean gas window, and it sits probably in the best place in the whole country relative to markets. So, we believe that you will see acreage turnover in the Eagle Ford and drilling begin. And 2017 could well be the year that you see that process starting.

Okay. Perfect. Thank you Tony.

Darren Horowitz, Raymond James.

Good morning guys. Jim, if I could, I want to go back to reference the comment that you made about ethylene cracking capacity ramping into next year. And I think we've got a pretty good idea of incremental ethane demand. But, more importantly, from an ethylene production or supply perspective, with the amount of polyethylene that is entering the market and the headwind that could have for ethylene prices, when do you think we get to a point where it starts to impact economics back to the well head and maybe it starts to challenge this ethane recovery incentive that we've been seeing to the extent that it swings ethane frac spreads regionally into a more negative position? Or does it not?

I'll take that --

Darren, we give all the hard questions to Tony.

So, if you just do the balances, you're adding about 50% ethylene capacity in the US, and it's along the US Gulf Coast. So, do we see regional differences in netbacks in the future? We absolutely do because, if you're going to run all of these plants, you're going to need supplies from areas that have what I will call stranded ethane at the current time. So that ethane is going to have to have a strong price signal for producers to plan on drilling it, processing it and shipping it to the US. I mean I think that's the bottom line. If ethane prices get too high, then we've said before that it's our anticipation that the merchant players are going to be I'll call it the odd man out because they don't have the value chain to produce polyethylene and the other derivatives. So, I hope that answers your question, Darren, but that's summarily how we see it.

It does, Tony, and I appreciate it. I'm just curious, as a follow-up, and we expect it the same way, as you see I think more volatility in regional ethane frac spreads, we see a tremendous amount over the next 12 to 18 months of arbitrage opportunity, and when you start talking about the value chain, incremental equity NGL barrels to be produced, let's just say at the Piceance, you went to Meeker and those plants, how do you see the biggest regional margin capture opportunity? Is it Conway to Belvieu? Is it possibly Belvieu to South or even West Texas, or maybe even more leverage, referencing an earlier question, on an arbitrage opportunity between the Marcellus and Utica in the Gulf Coast?

It's all of the above.

Okay. Thank you.

Kristina Kazarian, Deutsche Bank.

So, a quick follow-up. I know you talked about the Eagle Ford and the Haynesville, but when I was thinking about the press release talking about green shoots of producer activity, are there any other regions you guys want me to be thinking about where maybe you're seeing a little more than you were expecting at first?

We are seeing some acreage turning over in the Rockies, and we are seeing signs that people that are players in the Rockies are committed to the area in more ways than one. So, I would call some of the activity we are seeing in the Rockies a green shoot.

Okay. That's helpful. And then a clarification on the ethane side as well. I know you've gotten a lot of questions here, but can you touch on a bit what you guys are seeing, if any, of the chem companies maybe like stepping up and wanting to lock in some ethane capacity on your system as they are trying to secure supply for their facilities coming online? Any good updates on the margin there?

I don't know that -- I don't see that we've seen heck of a lot of that. The US ethylene companies, I think they act like -- they know that Mont Belvieu is a pretty liquid supply. I guess one place where they definitely stepped up was on our Aegis pipeline, because the subscriptions on that pipeline, if I'm not mistaken, are all petrochemicals. They stepped up and subscribed to our Aegis pipeline, and it's fully committed. So, I guess that's one example where they did step up.

And anything on the margin more recently in terms of like inbound requests?

Not that I recall. Tug? No.

Thanks guys. That's it for me.

Shneur Gershuni, UBS.

Good morning guys. I just had a couple of -- some follow-ups to some of the earlier questions, in particular the first two Brians. Just with Midland-to-Sealy, and I know we been beating this to a dead horse here, but basically at what point do you need to decide in the construction process whether you go at 300,000 versus 450,000? Is that the decision that you can make while construction is underway to actually upsize the pipe?

And then secondly, the discussion about ethane potentially needing to come from other regions and so forth. Have you been looking at an ATEX expansion, and is that something that we can hear about in relatively short order?

This is Graham. In regard to Midland, Midland-to-Sealy, when you look at the design and layout of a pipeline, you plan that -- you plan for the expansion and the layout so that you're not doing that after the fact. So that's incorporated into our planning for that particular pipeline.

So you can make the decision fairly quickly.

You can make the decision at any time.

In terms of your ethane out of the Marcellus, we could put projects in place to bring more ethane out of the Marcellus.

Is it something that you're looking at doing, or evaluating to do something in relatively short order, or is that something that would take longer, you'd have to sort of see the crackers come up and see where the market balances out?

It'd take 18 months from time of decision.

Okay, fair enough. And there was a discussion, I think it was with Darren, about ethylene and what would happen if the prices fell and so forth. And maybe this is a question for Tony to opine on, but is there a scenario where the US would, even if ethane was to go up, would still continue to move forward because of the fact that there are world-scale crackers that can potentially close or force other crackers around the world to actually shut? I was just wondering if you can sort of talk about that dynamic as to when it really would impact production on the merchant side in the US.

There are advantages of gas to crude. So if you believe that gas is going to sell at a low relationship to crude, then ethane can go up and there is still cost advantage to naphtha crackers in other parts of the world. Tony?

I completely agree.

We publish our breakevens. We think natural gas in the US is going to be extremely competitive for a long time. It has been and we believe it will continue to be.

Okay, fair enough. And one earnings question -- some pretty strong results in the crude segment. Any specific color on the strong performance? I realize it's sort of consistent with last year, but it's a pretty large step up from the prior quarters. I was wondering if you can sort of give us a little color as to why we saw that kind of strong performance there?

This is Bryan. Some of that shift, if you recall from last quarter, was mark to market movements. So you had kind of a reversal of that, and then you have improvement as well with respect to our EFS Midstream assets.

Cool. Thank you very much guys. I really appreciate the color.

Jean Ann Salisbury, Bernstein.

Just a couple about NGL exports. So, third-party reports suggest that overall Gulf Coast NGL exports had a really big rebound since the August lows, but Enterprise's volumes have actually kind of gone in the other direction. I know it doesn't impact earnings heavily because of the take-or-pay, but I was wondering if you had any comment to why this could be? Do your competitors maybe just have different contract structures?

Our competitors have a lot fewer contracts. I don't know if the ratio is different. We could have more cancellations and still have a lower ratio of cancellations to contracts. Joseph, have you got any thoughts?

Yes. We have seen the arb improve as we've gone through the third quarter and into the fourth quarter, and we expect that to continue and volumes to reflect that. I think we're fairly happy and pretty proud of our third-quarter export numbers, actually.

Okay. And then some of your take-or-pay for LPG exports does begin to roll off in 2018 and 2019. Are you actively remarketing that capacity and can it actually be remarketed as PGP or even other products?

The answer is we are always trying to -- we try to go out as far as we can. We don't wait for them to roll off. So Joseph continues to push for, and believe me he gets a lot of help around here, on continuing to push for more contracts further out. I think we are realistic. We are not going to see the $0.12 to $0.14, but one of the advantages we have for us is we've been doing this a long time, and people recognize that we deliver on what we say we will do. And we continue to have discussions. We sign people up.

As far as the propylene, yes, we put the capability to export propylene out at the Houston Ship Channel because we believe in it. And we've seen our cargoes -- we've seen a steady growth in our propylene exports, and surprising to me, we've even seen some go to Europe, Corey?

Yes, that's correct.

So, we kind of sit back and say, hey, this is another opportunity. You're going to have a lot of propylene in the US. You're going to have crackers I believe in other parts of the world that aren't going to run at rates or not run at all that typically were producing a lot of propylene and we think there will be a draw on what we have here.

Great. Thanks. That's really helpful. One last one is on the 25,000 or so of ethane that you have, I get you start it up and then start to sell it, but is there any opportunity for a spot ethane market, so to speak, or is it more like you would sell it for a cracker that would take a couple of years to convert to be able to take it?

It's pretty much point A to point B at this point in time. I'm not saying that it won't develop into a traded commodity, but it's going to be a while. All of our customers are petrochemical customers.

Great. Okay. Thank you very much.

Ted Durbin, Goldman Sachs.

Thanks. We've seen a lot of activity in the Permian -- actually out in the Delaware. Have you considered extending Midland-to-Sealy all the way out to the Delaware?

No. It's a good question, Ted, and we looked long and hard -- I might look over to Brent to help me here. We looked long and hard at building upstream of Midland. And frankly, there's a lot of PE projects that I guess will use leverage returns, Randy? And we looked at the return we would have to accept, and we said no thank you.

The reality is -- we really believe this -- we believe this where Cushing is concerned-- we believe that if we do our jobs right on the Gulf Coast, given our connectivity to every refinery in Texas City, Houston, Beaumont and Port Arthur, and given our access to water, and given the amount of storage we have, if we do our job right there, we are going to pull barrels through because the Gulf Coast is where a lot of these barrels want to be.

Okay, that's helpful. And then on Centennial, I think you said you can move 200,000 a day. Can you talk to us just about how much volume you would need to get contracted up to make that project to go? Is it half of that? And remind us if that's just propane or are you thinking about maybe an E/P mix there?

We are thinking about a lot of things that we are probably not going to talk about right now. I've got a partner that we have a high regard for, a lot of respect for, and we've been in discussions, and we are going to continue discussing a lot of ideas with Marathon. One thing I will say is that Marathon and Enterprise, given their position in the Marcellus, are very much aligned in what a solution might be.

Okay, great. And then if I can sneak one more in, can you give us a sense, as you're looking ahead to 2017, how the CapEx budget is lining up? Is it close to where we are with the 2016 growth capital budget? And then how do you think about distribution growth as you balance the need for financing the CapEx versus the $0.005 increase you've done for many quarters in a row?

It's Bryan. As far as 2017 expectations, we are really in the early stages of our 2017 budgeting process, so I would prefer to give you a qualified response than a wide estimate range, so more to come on that. But I don't think you will see any changes from what you've seen in the past with respect to distribution growth.

Okay. Thanks.

And the way we financed ourselves.

Understood. Thank you.

Jeremy Tonet, JPMorgan.

Jim, it seems like we are facing a brave new world of pipeline buildout these days given the regulatory and environmental concerns out there. I was just wondering if you could walk me through how you think about construction risks these days and how it plays into your business model.

I think our pipe in the ground is going up in value dramatically because of a lot of what's going on today. I think, as you look at constructing new pipe, you hope it's in Texas and Louisiana, and you probably put a little fudge factor in if it's anywhere else.

Got you. At this point, would it dissuade you from doing projects outside of kind of the areas you're in or are you just kind of risking it more?

We are going to risk-adjust the thing. We are probably going to take a hard look at our capital, but I don't think it's going to stop us from building where we want to build and where we need to build, where people want services.

Great, thanks. And then just one more if I could. I just want to follow up on what you're talking about with the Eagle Ford as far as maybe land changing hands there. And I was just thinking back, with the Pioneer acreage, just using that as an example, if that was to be sold to private equity or something like that, would the contracts move with that? Would Pioneer still be on the other side? Or how do you think about that type of scenario or that type of risk?

It depends on the kind of deal that someone like a Pioneer would do, whether they would wear it or the other person would assume it, but the contracts stay intact and we continue to get paid and move the barrels.

Okay, great. That's it for me. Thank you.

Michael Blum, Wells Fargo.

Thank you. I just had one question on the earnings for the quarter. In the press release, you talked about lower NGL volumes across Mid-America, Seminole, Dixie, a whole bunch of the smaller NGL pipelines. Can you talk about exactly what's driving that? Is that purely ethane, or is there other factors sort of driving the year-over-year declines in volume?

I'll start and then throw it at Bryan and anyone else who wants to. But I think we saw a lot of ethane rejection by Enterprise, Tug?, in the third quarter. And if you think about it, with our variable economics, if we are in rejection, it's pretty bad. So, I think that was a lot of it. Bryan?

This is Randy. The other thing I'd throw out too is we had Dixie on hydro-test on some of the segments there, and that impacted some of the volumes on the Dixie pipe.

Okay. Great. Thank you guys.

Nick Raza, Citigroup Research.

Good morning guys. Just a quick couple of questions on Centennial, specifically do think there would any sort of regulatory hurdles in getting that project done, assuming you lined up all the shippers and all the interest?

No, I don't think there would be any regulatory hurdles that I am aware of.

Okay. So, we would still be targeting sort of an 18-month turnaround for that project? I think we had sort of loosely discussed in prior quarters or prior earnings calls.

I think you're looking at 18 months.

Okay. And in terms --

Graham, is that about right? Graham is going to say 18 to 24.

You're reading my mind.

Fair enough. What level of commitment would you guys need before you start moving forward with that project? Would it be you need to have 60% of the pipeline, 70%, 80% all signed up and secured before you move forward?

There is a level -- I'm probably not going to say, but there is a level of commitment that we'd want that equated to an accretive return that had upside.

Okay. Fair enough. And the last question I had really was about the ethane exports. You sort of commissioned the facility in September, and the press release says that you had a $3 million loss. Was that just -- are we to assume that's just a one-time scenario specifically? What level of -- I guess what I'm really asking is what levels of ships do you guys need to sort of breakeven?

Let me put it like this. This thing ramps. I don't think the first really big ship comes in until December, Joseph?

Yes, that's right.

So this thing is going to ramp throughout next year, if I'm not mistaken. So it's kind of in its -- it's crawling right now before it walks. But it's kind of a natural, normal ramp that we are going to go through over the next year before it really gets loaded. Is that right? Year?

(inaudible - microphone inaccessible)

I'm sorry, I didn't catch that. So it's --

This thing ramps. This project ramps up over a year. So our volume will be small until all of the contracts are starting up, and I think they will probably start up by the first of the year and then ramp throughout the year. Joseph?

That is correct, yes.

Fair enough. Okay. And last question, in terms of the ethylene exports opportunity, has there been sort of a movement forward on that? If you can just give us a little bit of color?

We've gained some traction with some people. I think, you know, we will see. I think some of these people recognize they need -- they would like to have access to more markets. I think they are looking at Asia, and we feel pretty good about the project.

Personally, I don't think this is going to go fast, but I think it will go. I think we have a location we can put it that, as far as exporting ethylene, we could probably build it cheaper than anyone else. And you can imagine, if we do it at Morgan's Point, we are sticking it right next to our ethane export. So it kind of ties together.

Got you. Thanks guys. That's all I had.

This is Randy. We will take one more question.

John Edwards, Credit Suisse.

Good morning everybody. Thanks for including me in the last question. Just in terms -- Jim, you were talking in your preliminary comments in terms of uplift on ethane pricing, it's gone from $0.16 to $0.25, and I'm just -- this is probably a Tony question. Where do you think, the next couple of years, that pricing is going? Are you thinking the $0.35 to $0.40 range, or if that's wrong, if you could correct our thinking?

I don't look at it in terms of price. I look at it in terms of margin. But I'll let Tony answer it.

I think it's very difficult to call price, especially on something like ethane when you're looking at plants of this magnitude ramping up, and the amount of rejection that we have today. So that would be a hard price to forecast. We are not, as Jim said -- that's a trade. That's just not what we are about. But with that said, you know there's a fair amount of contango in the market today, so the market is trying to price it in contango, and give producers a price signal out in the curve.

Okay. So then you're thinking about it in terms of margins. What's kind of your thoughts along those lines?

I look at it, John, as what does it take to get to market. If these crackers come up and run at rates, then if I am sitting in the Permian or in the Eagle Ford, I'm looking -- I'm $0.10 to $0.12 a gallon away from the market. If I am in the Rockies or I am in the Marcellus, I am $0.22, $0.23 a gallon away from the market. If the market wants to attract those barrels, and if I am in the Permian, I'm $0.12 to the good after my cost.

Okay, fair enough. And then just, if I could, kind of a follow-on to Ted's question, just in terms of where you are on projects currently under development, would you say it's picking up a bit, about the same as last quarter, or maybe slightly lower than last quarter? Kind of where do those stand?

This is Randy. I think what we're seeing right now is we continue to see good traction on the projects that are under development.

I couldn't quite get to --

Yes. So I think we picked up some momentum here in the quarter.

Okay. So in terms of -- if I translated that into backlog, would you say it's a little bit higher?

(Laughter). Yes, you could say it's a little bit higher at $26 for crude oil, I didn't know if there was a backlog.

I'm just thinking since last quarter.

Yes, I do think it's a little bit higher.

Okay. So a little bit positive trending then?

Yes.

Okay, great. That's it for me. Thank you.

Jennifer, if you would, could you give our participants the replay information? Then after you do that, that will end our call. I'd like to thank our participants for joining us today. Go ahead Jennifer.

A replay of today's call will be available starting today, October 27, 2016, approximately two hours after the end of this call at 1 PM Eastern Standard Time and will be available until November 5, 2016 at midnight. If you would like to access this replay, you may dial 1-800-585-8367, or 1-855-859-2056. And for local participants, you may dial 404-537-3406. Again, this replay will be available from today at approximately 1 PM Eastern standard Time until November 5, 2016 at midnight.

Thank you. This does conclude today's conference call and you may now disconnect.