Enterprise Products Partners LP (EPD) 2016 Q4 法說會逐字稿

Good morning. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners fourth-quarter 2016 earnings conference call. (Operator Instructions)

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

Thank you, Regina. Good morning, everyone, and welcome to the Enterprise Products Partners fourth-quarter 2016 earnings conference call. Our speakers today will be Jim Teague, Chief Executive Officer of Enterprise's general partner, and Bryan Bulawa, Chief Financial Officer; followed by a few comments from Randy Fowler, our President. 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.

With that I will turn it over to Jim.

Thank you, Randy. Our business continued to perform well in 2016 despite a still-challenging environment. We reported gross operating margin of $5.2 billion in 2016 compared to $5.3 billion for 2015.

Distributable cash flow, not including proceeds from asset sales, increased to $4.1 billion, compared to $4 billion in 2015. We increased distributions to $1.61 per unit, a 5.2% increase compared to 2015. Distributable cash flow, not including proceeds from asset sales, provided 1.2 times coverage giving Enterprise over $700 million of distributable cash to put into growth.

Like the three previous quarters, we also ended the year on another strong note as we reported DCF of $1 billion for the fourth quarter of 2016, again 1.2 times coverage, and we retained $159 million in the fourth quarter of 2016.

In the area of growth projects during 2016, we successfully completed $2.2 billion of projects, including two new cryo plants in the Delaware Basin and our ethane export terminal on the Houston Ship Channel. In addition, we were successful in developing organic growth projects throughout this part of the cycle. Including our isobutane dehydrogenation, or IBDH, project we announced this morning, we now have approximately $6.7 billion of growth capital projects under construction that would be completed between now and 2019.

Our largest project, PDH, at our Mont Belvieu complex is expected to begin commercial operation midyear, and due to the increase in activity and expected crude oil volume growth from the Permian, we have decided to commission our Midland to ECHO pipeline at its full capacity of 450,000 barrels per day. We remain focused on organic projects, but more importantly, we remain focused on both the supply and demand side of the equations in order to enhance our entire value chain.

Once again we enter 2017 on solid financial footing, which includes the top credit rating in the space, low cost of capital, no IDRs, and support from a very strong general partner and a history of healthy distribution coverage. As we said in the press release, we would like to thank our team of over 6,700 employees for their contributions toward our success during a very difficult 2016. These employees are represented here today by our management team, so I'm going to take just a couple of seconds to highlight examples of some of the accomplishments of our folks.

In 2015, we said that to make our numbers in 2016 it was going to take cost management and commercial creativity. Graham Bacon is our Executive Vice President over Operations and Engineering, and he sits with us today. Their contributions were significant.

Our O&M costs as were reduced significantly during the year. Between 2016 versus 2015, repair and maintenance costs were reduced by $45 million, but this was in spite of the fact that we added significant assets, such as ethane export in our Delaware Basin and South Eddy plants. Our Operations and Engineering folks continue to follow a team approach in finding large and small cost savings across our organization, but they do it in a way without compromising safety.

Laurie Argo manages our crude oil, refined products, and nonregulated NGL assets, where we continue to grow. An example in 2016 is we added the ability to load polymer-grade propylene at our Houston Ship Channel facility. This required us to upgrade some of our assets in Mont Belvieu, and make modifications at the Houston Ship Channel.

With these new capabilities, our propylene group, led by R.B. Herrscher, went to work and we expect to load over 5 million barrels in 2017, which is double what we did in 2016. This is an area that we continue to focus on to grow.

An important milestone was in late December we not only sold the first polymer-grade propylene export cargo to Asia in many years -- and in fact, in my memory -- at 160,000 barrels that cargo was more than double the typical propylene cargo size and it is the largest cargo of propylene that we have ever loaded. We continue to be focused on being able to export virtually everything we touch.

Business in our NGL fractionation and storage assets continue to grow and break records. About two years ago we laid out what we expected to be significant increases in demand for NGL storage. Since that time, our team has been continually adding storage enhancements, including more brine capacity and additional receipt and takeaway connections, which allowed us to achieve record NGL storage and throughput volumes in 2016.

Our fractionation team has been focused on improving the efficiency and reliability of our fractionators, which resulted in our highest annual volume ever processed through our Mont Belvieu fractionators in 2016. And that was achieved in spite of significant ethane rejection.

Our Rockies team in Denver, led by Bill Bradley, also had a number of accomplishments. That's an area in the country where rig counts have been anemic, and from a midstream perspective, it is an area that is overbuilt for the current activity levels. Nonetheless, Bill and his team have gotten very creative in putting deals together to keep producers drilling and also pull substantial amounts of gas from other plants.

During 2016 this team termed up over 300 million a day, long term, for our Meeker and Pioneer plants. Bill and his team are close to their customers. They are creative and they understand their value chain. More importantly, they understand how to use it.

Another example of operations and commercial teamwork relates to how we approach our API 653 inspections that are required for aboveground tankage. Rather than put these inspections on autopilot, our guys work together to develop a rigorous review process to vet every tank before we take it out of service and spend the money for those inspections. That approval process now requires full economic review of the historical and forecasted profitability of each tank.

Meanwhile, operations and engineering revamped the inspection and repair procedures to not only to comply with new PHMSA regs, but also to include repairs that would prolong the time between inspection cycles. As a result of these coordinated reviews, we continue to realize substantial savings.

Finally, Brad Motal leads our natural gas businesses in Louisiana and Texas. In 2016 this team brought on two Delaware Basin gas plants and commercialized the first train at the new Orla plant in June. All underwritten by high-quality producers and all of the volume from these plants will feed the Enterprise value chain.

Finally, marketing at Enterprise is not a separate business. Rather, marketing is an integral part of each business. Brent Secrest leads liquid hydrocarbon marketing, but he comes to marketing from the asset side of both our oil and NGL businesses. Brent and his team understand our assets and most of our 2016 milestones. Frankly, any first-mover advantage in our businesses are possible because of marketing functions.

This year that group had the first very large ethane cargo loading; it was a ship that loaded 750,000 barrels. Had the first unit train delivered at Hutchinson, where I think we are having three to four unit trains a month for the next month nine months -- five unit trains a month.

This is the group that determined that they could take a well out of NGL service, put it in ULSD service, and realize strong contango opportunities. This is a group that is probably going to export record numbers of LPG this year, put on scores of barrels of contango, and take advantage of opportunities that invariably present themselves when chaos occurs.

Brent is also responsible for our marine and trucking business. Relative to those functions, our marine group is maintaining close to a 90% utilization rate in an extremely tough environment and our trucking fleet continues to run at high utilization rates. It may seem like an odd pairing of responsibilities- marketing, trucking, and marine- but our boats and trucks are usually the start or the finish of the value chain.

Wrapping this call up invariably -- we always speak to our results, but invariably people want to ask questions beyond what our results are, so we're going to preempt some of those questions. Relative to changes in Washington, which we expect to get asked our opinion on that, what we will say is we expect -- we look forward to more pro-business environment and less regulation.

As to prices, it's amazing the difference one year makes. Last year at this time oil prices were $30 and headed south, and with virtually no winter, natural gas was $2. In this environment most producers were hesitant to even publish a budget and would only say that they were going to try to live within their cash flow.

Today industry sentiment is 180 degrees where it was this time last year. Crude oil, natural gas, and NGL prices have recovered substantially. Costs have fallen. Rig counts and rig efficiencies continue to improve. Producers are increasing, rather than decreasing, their budgets and production is headed in the right direction.

We believe the news is especially good for US oil and gas. Everyone is watching the US, because they understand that we are the growth barrel. As painful as it has been, this downturn has proved the special qualities of the US oil and gas industry and proved its staying power. Now the news is either cautioning that US shale might grow too quickly or questioning whether the US can grow enough to meet growing global demand.

Our resources are plentiful and they are competitively priced. They are extremely short cycle. Last, but not least, they are risk-free in so many ways.

While we expect that 2017 will have its challenges, especially in the first half, we believe the worst part of the cycle is behind us. During the course of this downturn having to perform in the hard times sharpens your focus to reap even more benefits in the good times.

I will now turn it over to Bryan.

Thank you, Jim. I will discuss a few notable income items for the fourth quarter; provide an update on our growth and maintenance capital spending for the fourth quarter, along with our expectations for 2017; 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 fourth quarter of 2016 was $659 million, or $0.31 per unit, on a fully-diluted basis, compared to $685 million, or $0.34 per unit, on a fully-diluted basis for the fourth quarter of 2015. Non-cash impairment charges were $24 million, or $0.01 per unit, for both the fourth quarters of 2016 and 2015. G&A expenses decreased $10 million this quarter, primarily due to lower compensation and legal expenses. Provision for income taxes increased $17 million, primarily due to higher Texas margin tax accruals for this quarter.

Total capital spending in the fourth quarter of 2016 was $553 million, including $73 million for sustaining capital expenditures. Full-year 2016 growth capital expenditures were approximately $2.8 billion, excluding the $1 billion final installment payment made in July 2016 for the EFS midstream assets. Sustaining capital expenditures were $252 million. We also spent an additional $56 million for pipeline integrity work that was expensed in 2016.

For 2017, we expect gross capital exposes to be approximately $2 billion to $2.5 billion and sustaining capital expenditures to come in around $250 million.

At December 31, 2016, our total debt principal outstanding was $23.9 billion, the average life of our debt portfolio was 16.1 years, and our effective average cost of debt was 4.5%. Adjusted EBITDA for the 12 months ended December 31, 2016, was $5.3 billion and our consolidated leverage ratio was 4.4 times after adjusting debt for the 50% equity treatment ascribed by the rating agencies for the hybrid debt securities and to reduce it for cash and cash equivalents.

An important item to note and was referenced in our last two earnings conference calls is that we had more than $900 million of incremental debt, or an incremental 0.2 times of leverage associated with working capital tied to self-liquidating marketing opportunities across commodities. We currently expect a majority of the associated incremental debt to roll off in the first quarter of 2017.

Further, we anticipate gradual improvement in our leverage metrics over the next several quarters as late-stage projects come into service, the aforementioned short-term marketing inventory positions liquidate, and the increasing contribution of completed projects with the contractual ramp in cash flows, such as our ethylene export facility, our Aegis pipeline, our EFS midstream assets, and our ATEX pipeline.

As I've mentioned over the last several quarters, our disciplined approach towards appropriately managing leverage over the long term has not changed, where we continue to target leverage metrics at 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 $159 million of retained distributable cash flow that Jim mentioned earlier during the fourth quarter, we raised $372 million in net equity proceeds through our distribution reinvestment program, our employee unit purchase program, and the at-the-market, or ATM, program. Finally, our consolidated liquidity was approximately $3.8 billion at December 31, 2016, which included available borrowing capacity under our credit facilities and unrestricted cash.

With that I will turn the call over to Randy Fowler for some final comments.

Thanks, Bryan. The final regulations on qualifying income business activities were finalized last week, we think. As you recall, in May 2015 Treasury published proposed regulations requesting comment. There were material issues with the initial draft of the proposed regs, principally processes that were qualifying with respect to crude oil and refining were not for NGLs. And, secondly, there was a reliance on an exclusive list of qualifying activities.

Over approximately six months, Treasury held a public hearing, individually met with interested companies and the MLP Association, and received written comments. We applaud Treasury for the modifications they made to get the final regs. It did away with the exclusive list concept and its treatment of refining and processing activities for NGLs and crude oil are now consistent. We believe all or substantially all of EPD's business activities are qualifying per the final regs.

The question on whether the new regs are effective or not, pertains to the timing of President Trump's regulatory freeze and the dates the final regulations were filed and published in the Federal Register. There are varying views amongst law firms whether the regs are effective or not. We expect for this to be sorted out in the coming weeks.

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

Okay, Regina, we are ready to take questions from our participants.

(Operator Instructions) Jeremy Tonet, JPMorgan.

Good morning. Just wanted to follow up on your Permian outlook; it seems like things must be improving there given that the Midland-Sealy pipe was expanded here. Just wondering if you could talk about what you're seeing there, where the contract -- percentage contract it got to, and any other growth opportunities you guys see on either the crude oil or gathering and processing side in the Permian.

Take it, Tony?

Yes. Obviously, the Permian is the hotbed of activity; not just in the United States, but really across the globe. The stack pays great returns for producers, a fair amount of cache just attracting -- capital is going to the Permian. We have two new plants in service, another one under construction.

And I'm going to punt down to Brad; you don't think we're done there, do you?

I don't think we're done at all. I think we have got some great opportunities to continue to grow in the Permian.

As far as our Permian pipeline, I'd say that we are knocking on the door of 300,000 barrels a day of subscriptions, none of which is by affiliates. And we feel like there's more opportunities as we get closer to commission; that's why we decided let's go ahead and take it up to 450,000.

Great, thanks for that. Then maybe just pivoting to the Eagle Ford here. I think you might have talked about some green shoots emerging there in the past and just wondering, given the acreage that has changed hands, if you see any changing in activity there and how that would impact your systems.

This is Jim. When I don't want to answer a question, I kick it to Tony. So, Tony?

Jeremy, we think the Eagle Ford is a sleeper that people aren't paying attention to and I'll tell you what we like about what we see in the Eagle Ford. One is rig counts are up substantially and people don't realize that they've moved significantly off of their low and continue to add two to five a week.

The other thing that's going on in the Eagle Ford that is missed on many people is it's beginning to participate in its own stacks. What I mean by that is people aren't just drilling the Eagle Ford there anymore. They are also -- mostly drilling the Austin Chalk.

So we like what we see in the Eagle Ford. Our breakevens in the primaries are the Eagle Ford, and are competitive with the Permian as we run our half-cycle economics.

The other thing we are -- the last thing we are seeing in the Eagle Ford is we are seeing smaller players come in. So we think the Eagle Ford is going to be an area where you're going to go from a couple handfuls of very large players to smaller players, which is really opposite of what's happening in the Permian.

Great, thanks for that. I will hold it to two and hop back in the queue.

Shneur Gershuni, UBS.

Good morning, guys. Just as a bit of a follow-up to Jeremy's questions there, is the way that we should look at things right now you're okaying the expansion of Midland to Sealy. You've got the new iso plant on the board as well too. And then given your comments on the Eagle Ford as well too, is it fair to say that you're optimistic about 2017 being a much better year than 2016?

And as part of your Eagle Ford comments, I was wondering if you can sort of sensitize for us what you think the upside could be.

I think you said -- it's hard to understand and to hear you, but in terms of are we optimistic about 2017, I don't know. What's the difference between optimistic and hopeful?

We see the first half of 2017 as continuing to have its challenges. Even though rig counts are going up, we are going to lag that from a throughput perspective. Overall, though, I think we do feel more optimistic on 2017, definitely than 2016. And I could not hear the rest of your question.

The other part was whether you could potentially sensitize what the upside to the Eagle Ford could be for your numbers compared to 2016.

I'll answer that; this is Tony again. Rig counts bottomed in the Eagle Ford at 21. I think we ended over 50 this last week, so already significant improvement.

But you're going to see -- and I don't know exactly how much. You are going to see a lag from the time you start drilling and completing to the time the new production comes on. But I bet lag is months, so call it -- people project it to be anywhere from 90 to, let's say, 150 days from the time you deploy rigs to the time you put that production on. So we're going to see in the Eagle Ford something that is no sooner than back half of 2017 loaded, no sooner than, as far as increases in production.

And one final question, if I may. We saw a large amount of equity issued in 2016 and it seems your goal is for minimal equity funding in 2018. Comparatively speaking, when we think about 2017, where should we see issuances down relative to 2016? Are we talking about 50% less equity, 75% less equity?

I was wondering if you can give us a little bit of color as to how you think about equity issuances for 2017.

This is Bryan. Relative to 2016, it's substantially less, given that we raised over $2.5 billion of equity in 2016; 80% of which was in the first half of 2016.

So as far as looking forward to 2017 with a $2 billion to $2.5 billion type of growth capital spending range and then looking at our -- it's always a function of excess distributable cash flow. If you look back at the last couple quarters where we have ranged between $200 million and $300 million of issuance through the ATM, that's a pretty modest level and I would anticipate that we wouldn't really be exceeding those levels.

Great, so down materially from 2016. Great, thank you very much, guys. Really appreciate the color.

Darren Horowitz, Raymond James.

Good morning, guys. Jim, if I could, I wanted to go back to some of the comments you made in the prepared commentary around the $900 million of working cap that you've got outlined for the marketing segment.

I know this is tricky, but if you could, can you just give us a little bit more detail into the opportunity set there and maybe provide us a sense between the oil contango and grade-quality arbitrage and maybe logistical opportunities that you guys are seeing that might benefit the onshore crude segment versus some of the seasonal butane blending or any normal versus isobutane arb or even C5 opportunities that you are seeing?

Darren, you usually start out saying nice quarter, guys. What's the matter?

Jim, I thought that was a given.

Where we have our -- yes, we have had quite a bit of contango opportunities in particular. It's not unlike we had in, what, 2008, 2009.

It's funny how when you have a hard fall in prices invariably you get some real contango opportunities. I think where we've had the biggest bang for the buck, surprise, surprise, is in our NGL business, where we've got the storage and the connectivity to make that happen. We've done a good bit in refined products, especially in ULSD. And I have to guess; you are using 3 million, 4 million barrels of crude. 5 million?

From month to month it's between 4 million and 5 million.

So contango is the big one. You asked for regional spreads, again our NGL business lends itself to that, our system does; being able to do things from the North to the South or the West to the East. So there's been quite a lot of that tug.

You know, what we say is chaos creates opportunities that aren't otherwise there and we have been pretty good at trying to -- at picking those off.

I appreciate that. My follow-up on iBDH, and I know that there was some detail in the release, but when you think about 425,000 tons a year, is it fair to assume that maybe that might reflect a CapEx in the range of between $800 million to $1 billion? And maybe just looking at the overall blended return across your project set, an unlevered return in the 12% to 14% range?

You know we're not going to answer that, Darren. But if you want a job as an analyst over here, we've got three or four openings.

Well then, my follow-up will be a good one. Here is what I would really like to know from your perspective, and I think you are the guy to answer it. When you guys think about the arbitrage between normal butane and isobutylene, and I know you provided a lot of detail on the propane versus polymer-grade propylene that backstop PDH, can you just give me a sense for how you see that butane market developing?

Why don't you ask that again? Are you wanting to know what we think about normal butane in the future?

Well, I want to know what you think about the relationship between normal butane as a feed and, on a global basis, how fungible or how much demand we could see between the isobutylene side of the picture, because clearly you're filling that gap. And it seems like there could be a widening gap there, so I'd just love to know about what you think that project could mean to helping the supply side of the isobutylene equation.

This is R.B. We have over half of the plant termed up on over 15-year contracts and its feedstock basis, so that's pretty well set; secures the business. The rest of it is filling out existing derivatives, where we have capacity but didn't have enough isobutylene to fill it. So, for us, this is pretty much a sold-out plant from the start.

We are a believer in the long-term normal butane to isobutylene spread and we'll participate in some of that. And we will -- and some of it will be just feedstock-based.

Okay, thank you very much. By the way, Jim, good quarter.

Brian Zarahn, Mizuho.

Good morning. Turning to the Texas interstate business, can you elaborate a bit on the lump sum payment in the quarter and update us on roughly what percentage of the system is under firm demand contracts?

Do you know what percentage is under firm demand contracts?

Yes, following the lump sum payment.

We're about 74% on a demand basis on the Texas intrastate system.

And on Louisiana you're a higher percentage than that.

Higher percent than that, so --

In terms of what you asked about on -- what did you call it, a lump sum payment or whatever? We are constantly working with our producers to address their needs and this is just one of those opportunities that, frankly, when we do that we get a net positive overall.

Okay, and then I guess staying in the gas business, any updated view on activity in the Haynesville in your Louisiana system?

We are seeing that turn over quite a bit and, frankly, we are seeing rigs come back. We're seeing folks -- much like what Tony was speaking to in the Eagle Ford, it's going into hands that are willing to put drilling rigs out there. And Tony, I don't know what you -- do you show the rig count going up?

We do. So what you are seeing consistently in the Haynesville is, call it, two to three rigs a week on the plus side, and we don't expect that that is going to change.

The producers, especially the new ones, are applying new science that's never been applied in the Haynesville to great success. And its proximity to the LNG markets also whet the appetite of these producers and people that support them financially.

Our connectivity to the industrial market along the Mississippi River is a real positive for our system.

Appreciate the color. I guess turning to future M&A opportunities, perhaps imitation is the sincerest form of flattery as more MLPs are converting to a no IDR structure. But how do you view that impact for competition for assets going forward?

This is Bryan. I don't think it has really had a material impact at all. They are all -- as you know, the restructuring to get closer to us from a perspective of a -- cost of capital perspective so we remain very competitive. Probably you haven't seen us incredibly active in these last transactions as one of the key elements that you know to our long-term success has been remaining disciplined. And we continue to do so.

Appreciate that. Last one from me. You commented briefly on developments in Washington DC. If corporate tax reform does come to fruition, does that potentially change your future corporate structure?

Brian, one, I think we need to see what happens in tax reform. I don't think it -- it doesn't -- I think tax reform has only happened twice and it may come about slower than we think. But we are pretty open from a standpoint of whether it is to continue in the MLP world as a pass-through or if there's something we need to adapt to going forward, we are pretty open. I think our main focus is to be able to come in and continue to raise capital at an attractive cost.

Thank you, Randy.

Jean Ann Salisbury, Bernstein.

Good morning, just a couple quick ones. First, I noticed in the release that you said that ethane exports are going to 150 by the end of the year, but I had thought actually that 180 were sold. Is that true and are those still coming behind that?

Yes, there's a ramp on that.

Okay. So those will come in 2018?

Right.

Okay. Then how did the deferred loadings work? Do customers have to make up all the ones that they missed in fourth quarter of 2016 in 2017?

What you mean deferred loadings? You mean because of the fog?

I guess there was some because of the fog and then some because of the commissioning of the ships.

Do you know what we are asking, Joseph?

I mean, no, I'm not really sure what the question is.

LPG or ethane?

Are you talking LPG or ethane?

I'm talking about ethane. It sounded like several loadings were deferred in the fourth quarter and I was just wondering if those will show up in the first quarter.

We have our loadings and our contracts are backed by take-or-pay commitments. To the extent that weather has delayed the loadings, you'll see those show up when they are completed in the first quarter, but all of our ramp up and schedule is by the customers and their timing.

Okay, thanks. And then, secondly, in the Permian a lot of people, including myself, are trying to understand the gas takeaway situation out of the Permian. Do you have a sense of how much is flowing from the Permian to your intrastate system and is that expandable?

On a day-to-day basis we run pretty full from Waha South into South Texas and leaving -- going east towards the Dallas area. On a total basis, I'd have to get back with you on the number, but we do run pretty full every day.

Okay. And is that something that could be expanded as the Permian continues to grow?

We continue to look at that among other options.

Okay, great. That's all for me, thank you.

Tom Abrams, Morgan Stanley.

Thanks. Last up from me here is the ethane in the past week I guess was pretty weak. Just your color around that and if it sets up anything for the first quarter for you; how does it impact you?

We have had record inventory levels on ethane. I think it's just a matter of the market finally woke up and said there's record inventory levels. It will right itself, because you can make it go away by rejecting it. What it's done for us; probably given us some opportunities to do some contango deals.

Okay, as long as you weren't on the other side of that.

Say again?

As long as you weren't on the other side of that with positions, long positions into that.

We have a flat price policy that we adhere to religiously.

Thank you.

Faisel Khan, Citigroup.

Thanks. Good morning, gentlemen. I have one question on the Aegis and ATEX system, and then another question on the product pipelines.

First on Aegis and ATEX. The $30 million increase that you guys reported in the quarter from ATEX and Aegis, was that just the final service date of the third segment of the Aegis pipeline system or was there something going on here?

I think it's the ramp that we have inherent in both of those systems, Faisel.

So what are you guys running utilization at right now on both ATEX and Aegis?

I think we are hitting our subscribed numbers on ATEX and I think we're -- on Aegis, we're still ramping on Aegis. You still got some plants coming on, like Shintech, like Sasoil. So as those plants come on that will go higher to -- I guess.

Are you running at capacity? No. Are you running all you can given the customers you've got? Yes. Will you be at capacity as these new plants come on? Chockablock full.

Right, I'm just trying to understand the operating leverage to the growth.

On the refined product system, you guys talked about 24% increase in unloading and loading at your terminals in the fourth quarter over last year, but then if we look at gross margin it's basically down over last year. So just trying to understand what's going on there with that dynamic. Big increase in volumes and flat to lower margin.

Yes, basically we're getting more competitive and more aggressive to get the docks full. That's probably the answer.

Okay, that's almost -- you take away that 25% cut to margin though, if -- that's really what's flowing to the numbers. Just trying to understand what's going with the volumes and margin here.

This is Bryan. I believe there's also an $8 million mark-to-market loss in that segment, so it's a non-cash effect to gross operating margin.

And that should turn around when it goes to physical.

Then, Faisel, your other question as far as on Aegis pipeline, in the fourth quarter it was running 118,000 barrels a day and ATEX was running around 115,000 barrels a day.

Okay, great. Thanks, guys, for the information. I will try to get back in the queue or connect with Randy and Jackie offline. Thanks.

Brandon Blossman, Tudor Pickering Holt & Co.

Good morning, everyone. LPG exports have had a really great run to the back half of 2016 into early 2017. What should we look forward to in terms of just the dynamics there for 2017?

Guessing Europe has had a pretty strong pull here. Are those cargoes just going to Europe or are those incremental cargoes going somewhere else? And what does the durability of that demand look like?

This is Joe Fasullo. We've seen an increase in the fourth quarter of our cargoes going to Asia. And overall the market, the LPG market is fairly transparent as far as what's going out there.

We did see some slowdown internationally last year in the summer months and we may see that again just on an arbitrage basis this year, but it will really be the international market to dictate that. Some of the changes that we've seen this year are the decreased numbers coming out of Saudi Arabia and the Middle East, and that has been supportive to the exports this year that we had. We didn't see last year.

I think the other thing, Joseph, is you had a low crude price last year that probably created more demand for naphtha. With higher crude prices I would expect that you would expect to see more crackers globally using LPG versus naphtha.

Yes, absolutely. And we've seen a lot of crackers internationally hedge in their pricing this year and lock in their LPG pricing values as well.

Okay, nice color. Thank you, guys. I guess to follow up on Jean Ann's question, just to put a finer point on it; Delaware residue gas takeaway. You guys, Tony and Brad, see any -- are there any concerns out there in terms of constraints over the next couple, three years?

I'd say near term we think that it's going to start getting tighter and tighter as we've seen a lot of the producer curves, what they've shown us as part of their ramp up production, start to get to be some very large numbers. So, yes, there is some concern going forward about takeaway out of the basin.

Brandon, one of the wildcards there is what is Mexico going to take in the new pipes being built there and I don't know how to gauge that. That is a power generation market that's going to ramp up over time. And when I say over time, it's our understanding that you may be looking at six to eight years as the IPP plants are built in Mexico that those pipes were built to support.

So you can look at basis and you can see that the market is anticipating that the Permian is going to get tight on capacity.

Fair enough. Tony, as you look at the pipeline map, I assume that -- not to put words in your mouth, but it looks like there's some brownfield opportunities there; not just with you, but with peers. I assume that those are opportunities that are being looked at currently and we might see some announcements over the next 12 months.

I assume that everyone that's in this space and participating on the Gulf Coast side of the supply and markets is trying to figure out how we can move this growing volume of Permian down to where the demand is. And we are in that camp, I promise you.

Good news. Bryan, just really quick; leverage goals 3.5 to 4 times. As we model out over the next two or three years and incremental projects and EBITDA come online, where within that range would you expect to move to? I know it's a fine point, but just kind of curious is there a bias to one side or the other as we move through the next three years?

The PDH facility coming up and getting a full year of PDH and a full year of Midland-to-Sealy, so really you're looking at the end of 2018 when your figures, without any adjustments, would be probably inside of that range.

Okay, thank you.

John Edwards, Credit Suisse.

Good morning, everybody. Jim, nice quarter. But I won't give you a complicated question.

I just was wondering on the changes in the backlog, given the roughly $0.9 billion uptick sequentially, just how much of that from the iBDH plant you announced today or maybe any color you can give us on the mix there or what contributed to that increase in the backlog.

John, this is Randy. Really a combination of a couple things. You had a couple of projects roll off, smaller projects roll off, and then we added iBDH. And there was also some crude oil pipeline expansion projects over in the Permian.

Okay, that's helpful. Just I know you've answered a couple questions here regarding the NGL market. I just thought with all the steam crackers coming on, any other color you can give us regarding your expectations going forward?

This is Tony. I think if you just look at what the forward-pricing is today in ethane and you look at the contango in that curve I think that sort of says it all. Plants are going to come on. We put a schedule together as to when they are announced to come on. It will take them a little while to ramp up, but that demand is coming.

So we feel really -- and its substantial. Between now and, call it, 2019 you're looking at over 700,000 barrels a day of ethane demand coming on, so that's meaningful from a price standpoint. I don't know what else to say about it, John. We are very encouraged by what's happening in that space from a demand standpoint.

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

Barrett Blaschke, MUFG Securities.

Just one quick one and that is, if we're talking about Mid-America and Seminole Pipelines, it looks like the volumes improved dramatically. Could you just walk us through a little bit on what could improve transportation fees and then what's happening with OpEx that's driving it up?

Can you answer --?

We did see our OpEx go down quite a bit. I think about $32 million is what our margin was across this space, which was very significant. We also saw quite a few improvements in our volumes throughout the fourth quarter.

This is one of those places where our commercial guys are looking at back-filling. Where you have production slowdown, those guys are trying to work with our asset people, recognizing they don't know a hell of a lot what goes on on a regulated pipeline. But they're not stupid, so they know that if there's capacity and we've got allocation, we're going to fill it up.

This is Brent. If you look at the ethane margins that we saw in the fourth quarter versus what we'd seen year over year in the last nine months, certainly we are recovering more ethane in our plants. Then also, if you look at some of the spreads that we realized from Conway to Mont Belvieu that -- on propane and some of those products, we will probably add it to the volumes that Danika saw in her assets.

Okay. Then one follow-up and that's just kind of as we are seeing ethane rejection slow down and you guys think about further deploying capital and adding to backlog. Where do you go next?

Try to digest what we've got going right now, but I kind of like the way we have extended the value chain from C3s with our PDH, C4s with our iBDH. We like those projects. We think there's some more -- there's more that we're going to be doing in the Permian. I think Brad alluded to that. And we still think that the Eagle Ford is going to be a bright, shining star before it's all said and done and create opportunities.

I think what we have -- you don't have to be too bright to figure out over the last seven years we believe in market connectivity. And it's not just domestic market connectivity. I think a lot of what we are going to be doing is doing our job right on the Gulf Coast to attract barrels through our systems rather than necessarily going and fighting the gathering battle.

Okay, thank you.

Michael Blum, Wells Fargo.

My questions were addressed, thank you.

Christopher Sighinolfi, Jefferies.

Good morning, guys. Jim, just want to circle up on something you were discussing earlier with regard to Midland-to-Sealy. I think you had mentioned contracts there now stand at about 300,000 barrels a day. I just wanted to confirm that was -- I heard that accurately.

I said we were confident that we could get close to knocking on the door of 300,000 barrels a day, given the negotiations we've got going on. And given that, we decided we will just go ahead and commission to 450,000. That's not to say we've executed up to that level, but we are pretty damn confident we will get there.

Okay, understood. Thanks for clarifying. Then I guess to circle up on a question that we sort of hit on a little bit earlier, just the cadence of some of the ramps.

Obviously you guys have contractual ramps that continue in 2017 on the two ethane pipelines and also on Morgan's Point. I was just curious if there was something I guess more detailed you could offer about the cadence of that throughout the year. Or if that -- I think ATEX steps up in January, but if -- Morgan's Point, for example, if there are periods within the year we should be mindful of paying attention to.

Joseph, I think that ramps up well into 2018.

Yes, it does. Ramps all the way into 2018, but the majority of it does ramp throughout 2017 as customers continue to bring on ships and assets of their own.

So just sort of a gradual incline is how we should think about that?

Yes.

This is Randy. I don't have the numbers at my fingertips, but I would also refer you to our latest slide deck. There was a bar chart that both showed the ramp up for ATEX, Aegis, and the ethane export facility. And if you can't find that either call Randy Burkhalter or Jackie.

Yes, that's what I was looking at, Randy. I was just curious if there was something throughout the year that we could pay attention to, like intra-2017 is I guess my point, as opposed to just looking at the averages for the year. But it sounds like we should just model sort of a gradual ramp that gets us to those average numbers.

Help me, Tony and Danika. I think on Aegis you are going to see that thing ramp as these crackers come on along the Gulf Coast. And I think that pipeline's capacity is 400,000 barrels a day and once you're through with the ramp you're pretty well sold out. On ATEX, if I'm not mistaken, that ramps up to 130-plus and that is when? During the course of 2017 or is --?

Yes, and by the end of 2017 we are actually planning to complete our expansion as well to get us up to 144.

Okay, so we are taking ATEX to 144. Once we are through the ramp you are all but sold out and Aegis is when those crackers come on. So pick a time, Tony, 2018 and 2019, and, frankly, we are sold out on that one.

And then ethane export, I think that ramps from around 90,000 barrels a day at the beginning of the year to about 150,000 barrels a day at the end of the year.

That's about correct, yes.

Okay, and are you -- I know in your slide deck, Randy, you had featured sort of a window of option volumes. I was just wondering from your formal forecasts, like your internal budgeting, if you assume that those options are exercised or not.

No, we don't assume the options are exercised. On the ethane terminal, frankly, we got upside. That terminal will load 240,000 barrels a day.

We have said our operational rate will be 200,000 barrels a day; we're being conservative. Once we get some experience under our belt and a couple more contracts, I firmly believe we can take that up higher. Joseph?

Absolutely.

Thanks so much, guys. Really appreciate the time.

Selman Akyol, Stifel.

Good morning. Just a quick question on the Acadian Gas System. You had fees down there -- fees were down and then volumes were up by about 10% and I was wondering if you could just talk about the dynamics there.

Again, I think we -- this is Brad. Fees were down just slightly based off of some recontracting. As older vintage contracts rolled off we recontracted at newer rates.

Okay, thanks.

Regina, this is Randy. We have time for one more question.

Ted Durbin, Goldman Sachs.

Thanks. Any update on the Centennial conversion, enough contracts to make that a go?

Bill, you want to answer that?

We're still working on that. We've got several parties very engaged at the moment. We're not ready to take a victory lap quite yet, but it seems to be moving along reasonably well.

Okay, that sounds good. Then just talked about crude and gas, but NGLs out of the Permian. How much more room for you guys to move more out there or maybe the need to sanction a new project to get more NGLs out?

Depends on who you talk to, Ted. Right now we've got plenty of room to move NGLs out, notwithstanding what some of our folks think.

And on natural gas, I think it gets tight, doesn't it, Brad? I'm not sure how much expansion we've got in our systems, existing systems.

On the gas side we're looking at some significant expansion projects, but none of them are short lead-time. There would be some long lead-time projects to expand the intrastate system.

That's helpful, helpful. Then just coming back to iBDH, I guess it sounds like you've contracted half the capacity to third parties and the rest is going to be on your own systems. Just help us understand the returns on the contracted volumes. I guess is that hit your cost of capital, or how do we think about the moving pieces there?

Really what it gives us the opportunity to do is fill out our BEF plant. We've been short feedstocks.

The half contracted is at over 15 years. The other half is not necessarily uncontracted, but it's a little shorter term in our existing derivatives, the MTBE plant and the high-purity isobutylene plant.

We have not had any trouble selling those products at any point in time. We are seeing a lot more demand right now for MTBE in particular. And on high-purity isobutylene, you can pretty well sell it off?

Yes, sir.

So we feel like this is going to be a heckuva good project.

Okay, I'll leave it at that. Thank you.

Thank you. Regina, if you don't mind, would you give our participants the dial-in information or the replay information? We're going to go ahead and disconnect on this end and thank you for joining us today.

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