Enterprise Products Partners LP (EPD) 2016 Q2 法說會逐字稿

Good morning. My name is Jennifer and I will be your conference operator today. I would like to welcome everyone to Enterprise Products Partners' second-quarter 2016 earnings call. (Operator Instructions). Please limit yourself to one question and one follow-up question to allow for adequate time for all questions to be addressed. Thank you.

I would 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' second-quarter 2016 earnings conference call. Today our speakers 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 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, we 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.

Before turning the call over to Jim, I'd like to point out, as you probably noticed, there are a few minor format changes in the earnings release and exhibits. Based on recent public company guidance from the SEC, these changes give GAAP measures equal or greater prominence to non-GAAP. We will continue to disclose the performance in liquidity measures that we use in the management of our business, which include non-GAAP measures, that are reconciled to the nearest GAAP counterpart.

And with that, I will turn it over to Jim.

Thank you, Randy. Today we reported total gross operating margin for the second quarter of $1.3 billion, essentially the same as we reported second-quarter of last year. It's led to distributable cash flow of slightly greater than $1 billion, which is 5% higher than last year. Distributable cash flow provided a solid 1.2 times coverage of the $0.40 per unit distribution we declared for second quarter of 2016, which was a 5.3% increase over the same quarter of last year. This quarter marked our 57th distribution increase since our IPO in 1998, and our 48th consecutive quarterly increase. That's 12 years we have increased the quarterly distribution to our investors, which is unprecedented in our sector.

Our systems and our people continue to deliver in a very challenging environment. We reported record onshore liquid pipeline volumes and marine terminal volumes in the second quarter. Total volumes in our onshore NGL, crude oil, petrochemical, and refined product pipelines were up to 5.2 million barrels a day for the quarter compared with 4.9 million barrels a day for the same quarter of last year. Our NGL transportation volumes were a record 3 million barrels per day for the quarter, compared to 2.7 million barrels a day in the same quarter of last year.

The third and final segment of our Aegis ethane pipeline was completed in December, which are in these numbers. And these numbers also reflect the continued ramp-up of our Front Range and Texas Express pipelines. As to our terminal and dock activities, total NGL, crude oil, refined products, and petrochemical marine terminal loading and unloading volumes were 1.4 million barrels a day for the second quarter compared to 1.3 million for the second quarter of 2015. Natural gas activities, total onshore natural gas pipelines volumes for the second quarter of 2016 were 12.1 trillion BTUs a day compared to 12.5 trillion for the second quarter of 2015.

Fee-based natural gas processing volumes were 5 Bcf a day compared to 4.9 Bcf a day last year. Our equity NGL production increased 16% to 143,000 barrels a day compared to last year. Our NGL fractionation volumes for the second quarter increased 840,000 barrels a day. That compares to 822,000 barrels a day last year. These results continue to reflect the fact that we are being very aggressive in tying up volumes for our assets.

There's a lot of detail in our press release, so we're just going to summarize the results. Our NGL businesses continue to show strong results, led by new assets and volume ramp-ups. Processing margins remain challenged. However, integration has worked in our favor. Our crude oil pipeline and services business remains under pressure, negatively impacted by weak regional spreads generally caused by high inventories and falling domestic production. Nonetheless, demand is expected to continue to increase, especially at these low prices, and we believe we're well positioned for the volatility and the growth that is inevitable.

Natural gas pipelines and services business were hurt by weak regional spreads because of the nagging oversupplies, largely caused by last year's lack of a winter and falling production. We believe natural gas demand and the required domestic supplies needed to support that demand have significant upside, which will increase demand across all of our natural gas systems.

Gross operating margin from petrochemical and refined products services segment was lower compared to last year because of tighter margins, mostly caused by an oversupply of gasoline. That affects our BEF plant. Conversely, we are seeing nice increases in other of our refined products businesses, where our volumes continue to grow as we expand and integrate the former Oiltanking assets with our legacy assets.

Our petrochemicals and refined products are activities that complement several of our businesses that we definitely are focused on continuing to grow.

As to capital projects, we began commercial service on $600 million of growth capital projects during the second quarter. These included the South Eddy natural gas processing plant in the Permian, and the completion of over 2 million barrels of additional crude oil storage at our terminals in Houston and Beaumont. We are on schedule to put another $1.4 billion of projects online during the remainder of this year, including our ethane export facility on the Houston Ship Channel, and the Waha natural gas processing plant in the Delaware Basin.

And in fact, we are in the process of commissioning both of those projects as we speak.

In addition, we have $5.2 billion of growth capital projects scheduled to be completed in 2017 and 2018, which include our PDH facility, our Midland-to-Sealy pipeline, and completion of the crude JV dock in Corpus Christi.

Our commercial teams continue to progress on several projects that are in various stages of development. No midstream is more focused on market-related projects than we are. But it's important to note that we have announced several substantial supply-oriented projects since the downturn began, including three processing plants supporting NGL takeaway in the Permian, and of course our Midland-Sealy pipeline.

We're building organic projects during a trough period. To me, that speaks volumes about our people's creativity and the faith our customers have in us. These types of supply projects confirm that there still is demand from producers for new midstream assets. Or, more importantly, it speaks to the fact that producers don't necessarily want a one-off project from a niche player whose business plan is to flip their assets. Producers prefer someone with systems that give them flow assurance and market choices, as do consumers.

For our customers, reliability is more than a word that says you should expect an asset to run. Real reliability is having systems backing you that allow you to do things when unexpected operating or market conditions occur. That's what we bring to our customers, and why good projects come our way. In addition, virtually every project we do has a knock-on uplift effect across our systems.

Last, I want to take a minute to just take a look at what we see in the US market. Commodity prices have moved up significantly from the lows set in the first quarter of 2016, which is positive to everyone in the value chain, even the consumer. The move from $26 to over $40 in crude oil, and natural gas from less than $2 to $3, frankly was an easy call. The reality is these prices simply don't work. This cannot be sustained. The next $10 may not be smooth sailing, but it will be a key indicator for the world as to what US producers can and will do.

We believe the US producer was the first barrel off, but we also believe it will easily be the first barrel back on. When forward prices crossed the $50 threshold in the second quarter, we began to see signs that US producers and the capital markets that support them positioning for growth.

Producers are hedging. Rig counts are creeping up. DUCs are being completed. More importantly, we're having a lot of discussions with our customers and our producers and potential acreage buyers about services we can provide. These are positive signs that better times are ahead.

Before I turn it over to Bryan, I wanted to give you a quick update on our incident at Pascagoula. On June 28 we had a significant fire at our Pascagoula, Mississippi, processing plant. The most important thing was no one was injured. At the time of the fire, the plant was processing about 500 million of rich natural gas from various offshore facilities. As of today, virtually all of the gas has been rerouted to other plants in the area, and most of these delivered their NGLs into our systems. The investigation of the Chemical Safety Board is still underway, and we are cooperating. At this time, our best estimate is the plant will return to operations in the fourth quarter.

And, with that, Bryan?

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

Net income attributable to limited partners for the second quarter of 2016 was $559 million or $0.27 per unit on a fully diluted basis, compared to $551 million or $0.28 per unit on a fully diluted basis for the second quarter of 2015.

Net income and fully diluted earnings per unit included non-cash asset impairment and related charges of $13 million or $0.01 per unit for the second quarter of 2016, and $119 million or $0.06 per unit for the second quarter of 2015.

Depreciation, amortization, and accretion expense for the second quarter of 2016 was $360 million compared to $385 million for the same quarter of 2015. The second quarter of 2015 included approximately $61 million of expenses related to our divested offshore business.

After adjusting for these expenses, depreciation for the second quarter of 2016 was $36 million higher, with the increase primarily attributed to our acquisition of the EFS Midstream assets that we acquired in July of 2015, and new assets placed into service since the second quarter of 2015.

G&A expenses decreased $10 million this quarter, primarily due to overall compensation expenses and reimbursement of certain legal expenses. Total capital spending in the second quarter of 2016 was $884 million, including $58 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 $275 million this year.

At June 30, 2016, our total debt principal outstanding was $23 billion. The average life of our debt portfolio was 17.1 years, and our effective average cost of debt was 4.8%.

Adjusted EBITDA for the 12 months ended June 30, 2016, was $5.3 billion. And our consolidated leverage ratio of net debt to adjusted EBITDA was 4.2 times, after adjusting for the 50% equity treatment ascribed by the rating agencies for the hybrid debt securities.

I will point out that leverage is elevated by approximately 0.2 times due to over $800 million of working capital dedicated to NGL, crude oil, and refined product contango opportunities.

In the second quarter, we raised $877 million in net equity proceeds through our distribution reinvestment program, employee unit purchase program, and our at-the-market or ATM program. This includes $592 million of proceeds from the ATM issuances previously disclosed during the first week of April, and further discussed during last quarter's earnings call.

We have consolidated liquidity of approximately $4.7 billion at June 30, 2016, which included available borrowing capacity under our credit facilities and unrestricted cash.

On July 11, we paid the second and final installment of the $1 billion for the EFS Midstream assets that we acquired in July of last year. Following this payment, our consolidated liquidity was approximately $4.1 billion on July 11. As of this morning, our consolidated liquidity is approximately $4.3 billion.

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

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

(Operator Instructions). Darren Horowitz, Raymond James.

Jim, if I could, I had a quick question for you, first on the LPG cargo cancellations. And I realize you guys are covered on the deficiency payments, and of course the offset is higher PGP exports. But when you start thinking about some of the headwinds out there -- the lack of economic incentive between the Gulf Coast and Northwest Europe or even Southeast Asia; the fact that we've seen incremental butane being released into the market; and also, now, we've got this headwind of weaker crude oil prices hurting NGL spreads -- what impact do you think that has on the back half of this year's LPG loadings? And do you think the weakness lasts maybe into the first half of next year?

Darren, before I answer your question, you got to know, I leaned over to Randy Fowler and I said, I bet Darren is the first question on the line (laughter). This stuff has got to export; I mean, it's got to price to export. So if some prices in other parts of the world have to go up, or the price here has to go down; because Joseph, I think the freight has fallen to levels that I haven't seen since I was your age.

So, basically the spread's got to widen. And what that says is, probably the price goes down here. But the spread has got to widen, otherwise you're going to build too much inventory, and it has got to price to export.

Yes. If I could, as my follow-up, I just want to go briefly over to the ethane export facility. I assume that you all are still at about 160,000 capacity committed. I'm wondering what the headwind, as you see it, is to getting the rest of that capacity committed. Is it fair to assume that the first cargo should be loaded around August? And how does that volume ramp exit this year through 2017? How does that volume ramp increase?

Joseph, can you help after I answer this?

Yes.

Okay. The first cargo -- when is it coming in, 1 August?

August 1, yes.

Yes, our first ship will come in, Darren, August 1. We have an arrangement that's basically a way for us to start commissioning and our customer to start commissioning their ships. But we will load our first cargo in August.

And what's the ramp on the balance of the thing, Joseph, do you know?

The ramp is throughout the remainder of the year. A lot of it is being determined by the completion of projects on our customer's side, so it will be coming up throughout the balance of the year.

And by the end of the year, you ought to be -- everybody should be on schedule to load the cargoes that they have contracted for?

Yes, by the end of the year, we should be roughly at maybe 1.9 million barrels of exports per month.

Per month, okay. Does that help, Darren?

It does. Yes, thank you.

Jeremy Tonet, JPMorgan.

I just wanted to touch on ethane at first. With the crackers coming online in 2017 and the call for ethane increasing at that point, I was just wondering if you could walk me through how to think about what type of EBITDA uplift Enterprise could enjoy from the end of ethane rejection across your systems.

Jeremy, I'll take the first stab at it, and then turn it over to Tony. From an EBITDA standpoint, I think on the call back in May, we came in and gave you an estimate of 5% to 10%. And we came back in and worked some back-of-the-envelope calculations, and really that's about the range, 5% to 10%. And really where it is within that range is what your assumptions are.

So, with that, I will turn it back over to Tony.

In how we see the demand coming in (inaudible - microphone inaccessible)

Sorry, we can't really hear you there.

Sorry, I had my microphone off. So, let's call it the remainder of 2016 and remainder of 2017, somewhere over 300,000 barrels of incremental demand is how we have it for the crackers. We have about another 218,000 and another 219,000, then maybe another 100,000 in 2020. It's hard to tie these projects down, even for the operators. But there's just no way that this demand is not going to ramp up nicely over the next, call it, 24 to 30 months. And then, of course, you have exports on top of that that we think will total for the industry, call it, 300,000 barrels a day. So significant ethane demand is coming.

Great. Thank you for that. And just turning over to gasoline inventories being elevated here, I was just wondering if you could share your views as far as how you think that plays itself out here, and what impact that could have for crude oil pricing.

So, gasoline inventories obviously are elevated. Refiners have been running hard around the world. And some refineries in certain places of the world, think Europe, are going to have to throttle back to get it back in line. That's what will happen. Margins will take them there. I hope that answers your question. That's the way we see it.

That's helpful, thank you. And then just a last one. I didn't quite catch the ATM issuance. Could you repeat that for us, Bryan?

Sure. As far as -- well, for the second quarter -- well, I gave you the combination. I didn't give you the specific with respect to the ATM issuance. But in the first -- we had $877 million for the quarter, which was inclusive of the distribution reinvestment program, our employee unit purchase program, and our ATM. And of that $877 million, $592 million was from off of the ATM and that we had mentioned last quarter during our earnings call that occurred during the first week of April.

Great. Thank you for that. That's it for me.

Jean Ann Salisbury, Bernstein.

Just to follow up on the ethane question. So of the, let's say, 500,000 plus of new ethane demand coming, what do you see as Enterprise's largest constraint, if anything, to getting a large share of that increase?

This is Jim. I'm going to let this -- Bill, where's Bill? There is Bill. He can help me. Bill, we can -- first of all, we have capacity out of the Permian, existing pipeline capacity out of the Permian, out of the Rockies. So, to the extent processing plants out there react to increased demand, and we're going to have capacity to handle that. Where we would be a little -- we can add capacity down in South Texas, Bill? To bring on more ethane. And then, Bill, where are we -- we're constrained, as far as I'm concerned.

The one place we have some constraints is our ability to move more ethane on ATEX. In order to move more ethane on ATEX, it's not a small project to expand that capacity on ATEX.

And I think that capacity -- Danika or Daniel -- is what right now? 150-ish?

Yes, with the latest expansion, the pass-through will be about 145.

Okay. So our capacity is 145. Virtually with a 10% walk-up, we're fully subscribed. So any incremental -- that's where the constraint is in our system. Any incremental requires an expansion of that pipe.

Okay, thank you. That's helpful. And then on fractionation, it seems like you guys -- you actually don't have that much spare capacity on your net fractionation capacity. Could that be another potential constraint?

Fractionation is never a constraint. We always figure something out. And so, we've got -- we run our fractionation as a complete -- I don't care where it is. If it's in Louisiana, if it's in Hobbs, or in South Texas, we run our fractionation as one -- like it's in one location. We can move Y-grade around, so we can always find a way to handle more Y-grade.

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

Brandon Blossman, Tudor, Pickering, Holt.

One, let's circle back to LPG contract cancellations. Any further detail on the dynamics around those -- sorry, lifting or cargo cancellations? Any further detail around just the dynamics there? Our cargoes being sourced somewhere else, as far as you know? Or are these just not being delivered to the end user?

I think it has a couple of things, Brandon. First of all, we are in the middle of the summer, so this isn't the highest demand period of the year. From a petrochemical perspective, I guess there's a pretty good overhang of naphtha, which may be hurting the appetite of crackers in other parts of the world. But bottom line is what I said earlier: it's got to export; and it will export, in my mind.

The beauty for Enterprise is that as you read in the press release, what we have is more than an LPG facility. We have a facility that can export things like polymer-grade propylene and crude and refined products. So, yes, we had a few cancellations, but we had a record month in polymer-grade propylene out of our facility, too. But to answer your question, low-demand period, overhang in naphtha, but it will price to export because it has no choice.

Okay, fair enough. On ethane, it looks -- obviously price has been fairly volatile, at least in the last two or three weeks. It looks like we may have saturated that incremental demand, and perhaps a little bit of market share gains and then losses to propane domestically. Do you have any color on that in terms of where we are today versus a couple months ago? Supply/demand on it?

I don't think ethane is the only thing that's volatile. That's the -- the whole market seems to be volatile. The difference with us is, we embrace volatility.

Tony, can you answer his other questions?

We look at the feedstock preference for ethylene crackers every day. And what's happening today is propane is pricing itself to get in the crack in the United States. So, everybody can see it.

To Jim's point earlier about propane, propane has got to go. It either has to go in the crack in the United States; it has to go to storage -- storage numbers are very high, or it has to create demand by price in the US in crackers.

For exports.

For exports. So, that's 50,000, 100,000 barrels when propane gets in the crack that, over a time period -- it doesn't happen overnight -- you see propane demand coming up.

But to your earlier point, to the extent propane prices its way into the crackers, now you've created a domino effect on ethane.

Yes, okay. Thank you for that. I guess that's it for me for right now. Thank you.

T.J. Schultz, RBC Capital.

Sorry, just first, one quick follow-up on LPG. What cargoes specifically were canceled or where were they headed?

They don't give us -- I'm not being cute -- but if they are canceled, then I doubt they were headed anywhere. (laughter)

Joseph?

No, that's exactly right. They may have not had a home to begin with.

Okay, fair enough. On the PGP exports, you've talked about the short-term benefits due to some outages in Europe? But you've also talked about customers that have been looking to lock into longer-term feedstock contracts, similar to your NGL exports. So as we look at the PGP exports offsetting some of the cancellations, just any update on the ability to contract that on a longer-term basis?

Our strategy around propylene, frankly, is evolving. What I believe -- and I'll let R.B. chime in -- but what I believe is I believe it will be another product out of the US that other parts of the world will have an appetite for, which is why we put the capability to export propylene at our shipping facility. And we can expand that. We are, in fact, in negotiations with people for supply out of the Gulf Coast to other parts of the world. And frankly, I think that has the potential to grow.

R.B., did I say it all right?

You've got it.

Okay, thanks. Just lastly, quickly, in the Delaware Basin you've talked about the potential for I think multiple additional cryos beyond Eddy and the Delaware Basin JV. So you have announced the third plant.

But as you look forward -- and you talked a bit about your integrated system offering advantages on these supply type projects. Could you just frame what the potential is for additional capacity to be added in the Delaware specifically? And then maybe if we look at that 5.2 billion number you have coming online in 2017 or 2018, are there additional Permian plants in that number beyond what you just announced? Or is there upside there?

There's not additional Permian plants in that number.

But I will let Bill address the other projects.

There's not any additional plants in that number, but we believe there is significant upside. We built the NGL takeaway capacity from that area to handle significant upside. And we also built the -- or we will be building the gas takeaway from that area that we've talked about to handle that upside as well. So, really to plug in the upside, all we would need to build is the processing plant itself.

Okay. Thanks, everyone.

Kristina Kazarian, Deutsche Bank.

So, a follow-on, on the ethane side. It looks like we saw an uplift from some increased recoveries in the quarter. But we have always talked about this being a several-year process to that EBITDA uplift number.

So how should I be thinking about this quarter-over-quarter trend maybe continuing throughout the year, even if the cracker demand hasn't come on yet? Just general thoughts there would be helpful.

Kristina, this is Tony. So let's just assume that it's volume-driven, and that largely when you look at these volumes in some form or fashion, Enterprise is going to participate. We will get our share, whether it be in our liquids pipelines, our ethane distribution pipeline and our fractionators. But I can't tell you, while we look and say, look, we think there will be 350,000 barrels of incremental ethane demand in the 2017 timeframe, we can't tell you what quarter it's going to come on in. I think the people that are building those plants don't know that.

So, it's not a straight line. It's somewhat lumpy. And it appears generally between the 2017 and 2019 time frame, that it's front-end-loaded. I really don't know what else to say about it.

That's helpful, thank you. And then I know you guys touched on this earlier as well, but just to make sure I clarify here. On the $1.4 billion of capital projects you've got coming online in the second half of the year, just remind me how I should be thinking about that cash flow ramp-up on both the ethane export terminal and Waha.

Yes, cash flow will be more -- ramping up harder in the fourth quarter than the third. And then it really comes on strong in the first of next year.

Bill?

I think Waha, through the cash flow ramp-up, is going to be fairly quick. I think it's going to be full fairly quick. Whether that's the third quarter or early fourth quarter, I don't know, but we got a lot of gas behind pipe today that we can put into that plant as we speak. I think we talked about the ethane export facility already. If, in round numbers, I think about half the ramp-up will take place by the end of the year, give or take. And then the rest of the ramp-up will take place in the first half of next year.

Perfect. Thanks, guys. Nice job today.

Brian Gamble, Simmons & Company.

Tony, do you think the guys building those ethane crackers think the same way there? Or do you think they are a little more certain about when the demand is coming online?

It's funny; we watch what they say every quarter, and they are customers also. And you see some that say, I'm delaying. And then you see some that say, hey, I'm going to be early. So I don't know how to gauge it.

That's fair. I agree with your original statement. I think they are just as confused as anybody.

Jim, you were talking about that PGP evolving strategy there. Love the flexibility. Do you think longer-term, or maybe even shorter-term, that the potential for PGP contracting can be as profitable for you as LPG contracting could be? Or is there something there that would be a sticking point to change the margin structure between the two types of opportunities?

I think it's all relative. LPG, a much bigger market for it; so in terms of size, no. In terms of opportunity, yes. We firmly believe that we -- this market will export. And like I said earlier, we're negotiating contracts with people, mostly in this hemisphere. But we were in some meetings yesterday that made me think that this is going to become more global opportunities for our propylene than just this hemisphere.

R.B.? Damn, R.B. is doing good; he's agreeing with me (laughter).

Smart man. Switching gears, maybe talking petchem refined products for a second. I know you had the MTBE facility turnaround in Q1, a little bit bigger than normal; a bounce back in margin, but maybe not quite to the impact that I thought it might be for Q2. Can you talk about how that facility came back online in Q2, and what to expect as we go into the rest of the year?

This is R.B. The facility is operating very well. It's just a function of the weakness on the refined product side, the pricing, the gasoline prices; thus the MTBE pricing is low. But operationally it's performing very well.

So the gasoline overhang that we're looking at right now really limits some of the potential upside in the back half of the year, until we work some of those inventories off? Is that a fair characterization?

That's fair, yes.

We do have some hedges over in the back half of the year, don't we?

Yes, we do. Our back-half budget is pretty well assured.

Okay.

Great. Thanks, guys.

John Edwards, Credit Suisse.

Just wanted to follow up on the answer you gave to Jeremy's question earlier. So if I heard you right, I think you were saying there's -- you expect 300,000 of ethane demand for 2016-2017. I think you said 218,000, 219,000 in 2020, and then another 300,000 of exports. If I'm adding that all up right, that's 1 million barrels a day of demand coming. So do you expect, A, what kind of ethane price uplift; and B, do you expect shortages?

John, this is Jim. I'll turn it over to Tony. Those assumptions assume -- there's an assumption in there that crackers that are coming on, come on at the time we think they will; more importantly, that they run at rates. When you have this much ethylene come on, I'm not going to bet that they are going to run at 90% plus. I'm sure my former colleagues at Dow love hearing me say that.

But in theory, yes, you are -- to the extent that you have to attract barrels from further away, then at a minimum you've got to look at the T&F associated with that in a gas basis. Then we should see margins expand on ethane as that rolls forward.

Yes, and we've said all along that what's needed is a price signal to producers. And that is just what has to happen. And I think just about everybody that analyzes that ethylene market, that's not a market that we're in, but everybody that analyzes it says that ethylene is going to be oversupplied in the US.

Which is why, frankly, we're looking at an ethylene export facility.

So, translating that, then, some of that steam cracker demand may not be as strong as maybe -- in answering Jeremy's question earlier?

That's right. This is -- when I gave you those numbers, we looked at traditional operating rates that are operationally dictated. Because that's been the environment in the US, except for some feedstock switching. Now we're talking about -- on the commodity side that you are creating, you are talking about what do you do with all that commodity.

Yes, and one more point. We say, well, ethane prices, will they go up, and what will the margin be? It still comes down to gas to crude. And you still -- if you believe crude prices are not sustainable at this level, and you believe there is plenty of natural gas in the US, then you have to believe that the gas to crude price is going to be supportive of ethylene plants in the US versus ethylene plants in other parts of the world.

So, you can have ethane go up, you can have margin expansion between ethane and natural gas, and it would still be cost advantaged relative to other parts of the world. In other words, there is room here for everybody to win.

All right. That's really helpful, thank you so much.

Danilo Juvane, BMO Capital Markets.

Most of my questions have been hit, but I did have one quick question on the quarter. I think you reported $1.2 billion in gross margin. But was that a clean number, or were there some non-cash items in that number?

Bryan?

Danilo, this is Randy. It was a fairly clean number. We had the one-time items that you saw in the press release were below gross operating margin, so it was fairly clean.

So the number includes -- or excludes the $47 million market loss from crude oil marketing?

Well, yes, it does include that. Sorry. Misspoke on that.

Okay, got you. Okay, thank you.

Faisel Khan, Citigroup.

Going back to the LPG export cancellations, if I can ask the question another way. The cancellations, did they come from customers that are based in Europe, Asia, or in the US, which would include your marketing business?

Well, our marketing business does not lift cargoes. We sell FOB. And probably we're not going to answer the other part of the question.

Okay, fair enough. Is it fair to say that the -- as you canceled the propane export cargoes, but then you've ramped up the PGP exports, at the end of the day, the propane is being used to produce propylene. So is it just satisfying that end demand through the export of PGP? Because these PGP volumes came out of nowhere, so I'm just trying to understand the market dynamic there.

We've been exporting PGP for a period of -- for a while. But the change is we're exporting more than we ever have. We think it will grow, and we're exporting it from our own facility. And yes, we talk about, okay, we've had a few cancellations. Frankly, those were not a surprise to us, and we're still going to export 11 million, 12 million barrels on month, Joseph?

So, we get a little bit hung up on, oh, God, there's cancellations. Well, we kind of expected them. We didn't make any less money. We backfilled with propylene. And I'd say it's a pretty good position that we have.

Okay. I guess my question is, the backfilling with propylene, is that to satisfy the end demand that's being -- the end demand for propylene that may have not been -- that was not being supplied by the use of the propane cargoes being used in PDH facilities in other parts of the world?

Yes, I think most of the propylene we have exported has gone to -- this has stayed in this hemisphere.

Most of those PDHs are in Asia, R.B.?

That's correct.

So, no, it hadn't displaced PDH produced propylene in China. It's in this hemisphere.

Okay, okay, got you. And then just on the consistently high volumes for NGL equity, volumes were at 143,000 you reported during the quarter. Was there any sort of benefit from the ramp-up of the new South Eddy plant?

I think very little in the quarter, because we started up that plant toward the end of the quarter. I think the big change in the equity was the -- our ability under variable economics to recover a lot more ethane than we recovered in the second quarter last year. What I call the discretionary ethane, when our producers are likely to reject the ethane, we have the opportunity to recover it. And I think we were -- if I looked at the numbers, my belief would be we recovered a hell of a lot more in the second quarter this year than we recovered in the second quarter of last year.

Okay. And then a last question for me. Your CapEx spending plan, I'm just trying to make sure I understand this. Have those spending plans changed at all for the rest of this year, and for going into next year?

Not really. We've been pretty consistent on the $2.8 billion for the year. And there really hasn't been any change, with the exception of adding another processing plant that we announced last quarter.

Okay. Just wanted to make sure. Thanks, guys. Appreciate the help.

Richard Verdi, Ladenburg.

I just have a couple high-level questions here. Looking back historically, Enterprise has clearly been very successful in its organic and inorganic growth strategy. And currently there's a few billion dollars of capital projects on the table.

So, I'm wondering on that inorganic side, I'm sure the Company sees a number of potential deals on a daily basis. So I was wondering if you could give us a sense of where Enterprise sees potential for inorganic growth on both the type of market front and from a region standpoint.

I think sometimes people overlook that within the last two years, we've done over $8 billion of acquisitions. And we have successfully digested those. Sometimes we just do it more quietly. We continue to look at M&A opportunities, and that's one part of the thing we have always done. And so that's part of -- one of the ways we think about growth in the future. But, again, we're pretty choosy on the opportunities that we pursue.

But is there any area of interest, or is it just broad, and we'll take the opportunities as they come?

Yes, I think it's more broad, and we will take the opportunities as they come.

Okay. Okay, thanks. And then the second question is -- looking through the facilities under the Enterprise umbrella, it appears the Company has been more supply driven rather than demand, with the demand side picking up over recent time. And then when considering the ethane export facility that's expected to be up and running, that appears, at least to me, it will put Enterprise at more of a 50-50 split of being supply- versus demand-driven.

So if I'm correct, was there an internal decision to transform the Company into more of a demand business? And can we expect that trend to continue moving forward? Or can we expect the supply-driven side to pick up once again, or maybe even remain a 50-50 split? Just some color would be really helpful here.

I think we have always been equally focused on the demand side as we are on the supply side. And if you look at some of our more recent projects, Aegis is a demand project. It's an ethane header that goes from Corpus Christi, Texas, to the Mississippi River. The beauty of it is there's no decline curve. The PDH plant is a demand project. Our exports, as you rightly point out, are demand projects. We like the idea -- the PDH was an extension of our C3 value chain. We have said before that we would like to extend our C4 value chain. And we've said before, we have been very open, we are looking at an iBDH plant.

So I think your observation is right that we have been -- we are looking at demand projects. But it's wrong in that we've always looked equally at demand projects. Will we do supply projects? I think the Midland-Sealy pipeline is an indication that, yes, we will, for the right basins. I think what we are doing in the Delaware Basin is an indication that we like that basin, but we're going to be pretty picky in that regard.

Okay, that's great. That's great color. Thank you very much for the time, guys.

Michael Blum, Wells Fargo.

Just quick for me. So what is total ethane rejection across your system? And then Tony, if you have an updated view of where we are from an industry perspective. Thanks.

Yes, we never quote what ethane rejection is on our system. And one of the issues that we have is people define that in different ways. And so, I know that I can look at Enterprise's number, where we've been saying that, look, we think it exceeded 600,000 barrels for the industry. While other people have quoted much smaller numbers at that time. And I think it really is from a definition standpoint.

So, the way we look at it is what's coming out of the rock that is ethane? And then, what's being actually produced as ethane? We take the difference. So ours is probably on the extreme side, when you define ethane rejection.

With that said, for us, I have to tell you, it varies almost day-to-day. We look every day at every plant and every recovery, and determine what we think -- I mean, to the hair -- what we should be doing. So, it is not static at all. What we are doing today could change, and probably will change tomorrow. That's just how it works.

But using the big example, you are over 500,000 barrels a day, using our methodology today.

Thank you.

It may not be the same for tomorrow.

Got it. Thank you very much.

Selman Akyol, Stifel.

I think you have alluded to this one already, but on the margins for octane enhancement, they were down pretty significantly, all tied into refined product demand?

Yes.

Okay. And so a weak outlook for the rest of the year there, as well, then?

A weak outlook for the rest of the year. But as Jim mentioned earlier, fourth quarter -- we did hedge fourth quarter. And so, as far as plan, we're pretty secured in that plant.

Okay. And then just in terms of thinking of storage with all the inventories out there, can you just talk a little bit about what you're seeing in the storage market in terms of rates?

That's probably the most undervalued service in the industry right now. But we are seeing a high demand for storage. All you got to do is look at the numbers and you can probably back calculate that, wow, everybody has got a lot of stuff stored in their caverns. And we're not unique in that respect.

But from an Enterprise perspective, it's opened up quite a lot of contango opportunities. As Bryan mentioned, you said we got about $800 million tied up in working capital in contango?

Yes.

And we're not going to be afraid to do more.

All right.

But to your point, we see storage -- yes, I remember, it wasn't that many years ago that NGL storage went for $0.65 a barrel, and they'd give a couple of free turns, and maybe you would get $0.05 throughput. Today, R.B. or Bill, we're probably getting -- we're knocking on the door of $3 a barrel and between $0.15 and $0.20 throughput with no free turns. So, in crude oil storage, you are not having any trouble, Brent? You guys aren't having any trouble leasing out your storage tanks as we bring them on.

That's right.

And I think the same thing is true in refined products. And then when we have some left over, we will dole a little bit out to R.B. for petrochemicals.

All right. Thank you very much.

Tom Abrams, Morgan Stanley.

Just a couple-three questions. Propylene versus LPG profitability, you suggested in one of your answers that they were similar in the second quarter. Is that true? And then secondly, what has been the historic relationship between those two? Are they -- can you flip between them quite easily without profit concerns?

First of all, I'm sorry, I don't remember saying that. So if I did, it was a misunderstanding.

But you said you replaced some LPG exports with propylene; it didn't matter to you.

Oh, it doesn't matter. Well, I'd rather export LPG with the contracts we've got, frankly. But I also said propylene is an evolving strategy. To your point, we don't interrupt any LPG by exporting propylene. We've got the capability to do both. We may slow one down in order to take advantage of the other, but those refrigeration systems we put in can load either.

R.B., is that good?

That's good. And just a reminder, the volume of propylene compared to LPG is just a small fraction.

Yes. I mean we're loading 50,000 barrel ships and making pretty damn good money on those 50,000 barrel ships, R.B.?

Right, yes.

Tom, this is Randy. And what we had in the press release, the cancellations that we were speaking to work with respect to July and August, so not in the second quarter. And really it was the combination of the cancellation fees plus the incremental margin from doing the PGP exports that together offset the LPG.

Okay. And then just remind me on the Pascagoula fire, the net financial impact you expect. And is there any timing differences with receipts of insurance and the actual costs?

Tom, this is Randy again. In the second quarter number, I believe there was a $7 million charge with respect to the Pascagoula facility. That's based on the information we have at this time. As Jim pointed out, the Chemical Safety Board is still coming in and evaluating the facility. So, we're beginning to evaluate the facility. But as far as coming in and really knowing what the cost to get that facility back up and the definitive timing, we're still developing that.

All right. Then lastly in the crude segment, you had that non-cash item in there and maybe some volumes were weak in differentials. How does that move forward over the next couple of quarters? How should we think about that profitability evolving?

As far as the mark-to-market piece on our crude hedges?

Whatever is moving in that segment that my drive it one way or the other, please.

So, obviously as price has come down from a mark-to-market perspective, that's going to show up on the crude books for this month. So it's really a relative of the price of crude. As crude goes down, it's a positive; as crude goes up, it's a negative.

Is it volumes in any particular basins that we should be watching?

I'm sorry?

Are there volumes in any particular basins that we should be tracking or concerned about?

No, those are just hedges across the board, and so it's not necessarily specific to one area.

All right. Okay,

Ross Payne, Wells Fargo.

Bryan, some MLPs are giving us pro forma leverage metrics for partially completed projects that are not yet providing cash flow. I know you may not have this specifically. But given the substantial CapEx spend for this year and next, can you give us a general range of how much lower leverage might be if pro forma treatment might be applied? Thanks.

Sure, Ross. It would be probably somewhere around 0.3 times.

Perfect. Thanks.

Gabe Moreen, Bank of America Merrill Lynch.

My questions have been answered. Thank you.

Helen Ryoo, Barclays.

Just a quick follow-on, on ethane export projects. So on the contracted volume, do you get full economics if cargoes are not lifted? Or is it similar to the LPG contract, where you get some type of cancellation fee if cargoes are not loaded?

In general, it's similar to the LPG's; cancellation fees are a little bit lower than the full loading fees. But that can be offset some by variable cost as well.

All right. Is it -- in terms of magnitude, is it more than 50%? Or are you able to quantify what that level is -- what you get paid if it's not lifted?

Helen, this is Jim. I can barely hear you.

Yes, sorry. Sorry. Is it better? So I was just asking the cancellation fee, are you able to quantify what that level is versus the full economics you claim?

I think in general -- and I will let Bill tell me if I'm wrong -- in general, while the cancellation fee may be lower than the terminaling fee if they lift, it's only -- you are still making virtually -- pretty much the same amount of money because you don't have a variable cost associated with lowering it -- loading the cargo.

Bill?

Yes, it's pretty close. And the cancellation fees, the ratio to cancellation fees to the loading fees and the ethane is very, very close to what it is in our LPGs.

Got it. Thank you very much.

Jennifer, this is Randy. We have time for one more question, if you have one in the queue. If not, then that --.

Chris Sighinolfi, Jefferies.

Jim, I'm not sure if this is for you or for Bryan, but I was just -- one question I guess on structure for me. Clearly you guys don't have any challenges raising capital. But thinking about, at least from our vantage point, we see some -- what we would categorize as inferior companies relative to Enterprise, trade either on top of it or at a premium to it, merely due to the fact that they are structured as C Corps. So I was just curious if you had any thoughts about structure over time to perhaps introduce a security that would be organized that way.

Chris, this is Bryan. We look at a lot of things, and certainly study different structures. We are pretty happy with where we're at. Think it works pretty well, and certainly over the long run it has proved well. If you have the right structure and actually perform -- or use the structure, not abuse the structure -- it works quite well. So we will continue to evaluate other options. But at this stage, we're happy with where we're at with the one security and keeping the story simple.

Okay. Perfect. Thanks again, guys.

Okay, Jennifer. If you would, would you give our listeners the replay information for our call today?

A replay of this call will be available beginning today, July 28, 2016, at approximately 12 PM Central Standard Time until August 4, 2016, at midnight. To access this replay you may dial 800-585-8367, 855-859-2056, or 404-537-3406 at any time during those days. You will be asked to provide the ID number of 50282348. Again, the phone numbers are 800-585-8367, 855-859-2056, or 404-537-3406, with the ID number 50282348.

Okay, thank you, Jennifer. And thank you, everyone, for joining us today, and have a good day. Thank you. Goodbye.

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