Good morning. My name is Brent and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners First Quarter 2015 Earnings Conference Call. [Operator Instructions]. Thank you. I would now like to turn the call over to Randy Burkhalter, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Brent. Good morning everyone and welcome to our conference call this morning. Our speakers today will be Mike Creel, CEO of Enterprise's General Partner, followed by Jim Teague, our Chief Operating Officer and then Randy Fowler, Chief Administrative 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 21-E of the Securities and Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by and information currently available to, Enterprise's management team. Although Management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And with that, I'll turn the call over to Mike.

Thanks, Randy. We're pleased with our solid financial results for the first quarter. Contributions from recently acquired assets and from $4.4 billion of newly constructed assets that began service last year and in the first quarter this year, combined with lower operating expenses effectively offset the negative impact of lower commodity prices and a milder winter. Our onshore crude oil segment, petrochemicals and refined products segment and offshore segment reported a collective $105 million increase in gross operating margin, which more than offset the $101 million decrease in gross operating margin from our NGL and natural gas segments. Overall, our pipelines operated at high utilization rates. Compared to the first quarter of last year, crude oil pipeline volumes increased 8%, to a record 1.7 million barrels per day and refined products pipeline volumes increased 14%, to 803,000 barrels per day, while total natural gas pipeline volumes were flat, at approximately 13.1 Bcf per day. Volume on our NGL pipelines was down by approximately 5%, to 2.7 million barrels a day, primarily due to lower ethane recoveries and the effect of the warmer winter on propane deliveries. Earlier this month, we announced an increase in our quarterly cash distribution to $0.375 per unit, with respect to the first quarter of 2015. That's a 5.6% increase over the distribution declared with respect to the first quarter of 2014. This is our 43rd consecutive quarterly increase and it's our 52nd increase since our IPO in July of 1998. Enterprise generated $1 billion of distributable cash flow for the quarter, providing 1.4 times coverage of the cash distribution and we retained $295 million of distributable cash flow to reinvest in the growth of the partnership and reduce our reliance on the capital markets. Gross operating margin from our NGL pipelines and services was down…

Thanks, Mike. Opportunity knocks every day in our business. In a volatile environment like we're in today, opportunity still knocks; it's just a different opportunity than what we saw this time last year. The key is to recognize that knocking as an opportunity. Our quarter is the result of our hardworking, engaged and creative people recognizing the new opportunities that are created from volatility. Their mindset is to embrace volatility and not be victimized by it. It's very seldom that Enterprise looks backward, but I think it's worthwhile to start today with a look back at commodity prices one year ago, because I think it helps to have confidence in how our people perform through different parts of the cycle. Natural gas enjoyed a nice run this time last year, because of a brutally cold winter, so it averaged nearly $5 in the first quarter of 2014. It didn't catch that wave this winter and was down about $2 or 40% year-over-year and it continues to be weak. While we prefer higher prices, low natural gas prices aren't all bad for Enterprise. Cheaper natural gas lowers our feed stock cost for processing and gives us access to cheaper fuel in our plants and it lowers our power costs. Most of our natural gas transportation contracts have demand fees, so our transportation revenues are largely sheltered from low prices. Ethane is down $0.15 a gallon or 44% from this time last year, when it was already low. That does hurt some of our processing margins in plants where we still have some exposure and it can impact volumes and revenues in some of our NGL pipelines. However, over the last few years, we've converted our processing to fees instead of percent of proceeds, including going to fees on all of our…

Thank you, Jim. I won't be able to top that. I would like to begin with a few comments about the large decrease in revenues, since the general business media seems to focus on that measure. Revenues and operating expenses are influenced by changes in commodity prices and are not necessarily the best indicators of the performance of a midstream company. For example, in the first quarter 2015, primarily as a result of lower commodity prices, our revenues were down 41%, to $7.5 billion, but our costs and expenses were down by 44%. This is why we believe gross operating margin and distributable cash flow are better performance-based measures. By the way, DCF was up by 4%. Now, I would like to discuss additional income items for the quarter, as well as capitalization. Net income was $651 million for the first quarter of 2015 or $0.32 per unit. Net income and EPU were reduced by non-cash impairment charges of $33 million or $0.02 per unit in the first quarter of 2015. So adjusted for the non-cash impairment charge, adjusted EPU for the first quarter 2015 was $0.34. Since the fourth quarter of 2013, we have had a reconciling item between non-GAAP gross operating margin and net income for non-refundable revenues attributable to shipper makeup rights on certain new pipeline projects. These are from non-refundable fees received from shippers for unutilized pipeline capacity. This quarter, the deferred transportation revenues included in gross operating margin, but excluded from net income was $31 million. Of note, with respect to these deferred revenues, in the first quarter of 2015, for the first time, we recorded revenues that had previously been deferred. The revenue recognition was either due to shippers utilizing their contracted pipeline capacity that was previously paid for or upon expiration of their…

Okay, Brent. We're ready to the take questions from our audience.

[Operator Instructions]. Your first question comes from the line of TJ Schultz with RBC Capital. Please go ahead with your question.

Really just a couple questions on some of the new projects that you all discussed at the Analyst Day that I guess are not yet in your backlog, per se. So first, there was an indication for a potential second ISO butane dehydro unit with the comment that it could provide a step change, I guess, to growth in the pet-chem segment. Just any update on that potential project, around timing, cost, returns?

Other than we continue to work that project, we like what it did to our C-4 chain. But beyond that, we're still hustling, but we're not there yet.

Okay. Any update on the potential Northeast propane takeaway solution, I guess moving into some of the Midwest markets? What those customer discussions stand right now?

We're talking to three or four people, frankly. I think after last winter, it was going to be difficult, because people didn't have a problem. I think this summer is going to be where the rubber hits the road, as people are selling at pretty steep discounts. So I think the winter we had last year probably delayed the appetite. But it is a very good project that I would expect and hope to see done.

Your next question comes from the line of Matthew Phillips with Clarkson Capital. Please go ahead.

So your NGL transport volumes declined sequentially a bit, but margins were as goods as any time in recent memory. Was that mostly due to regional spreads? Or was there some sort of storage contango component there? And how should we look at that for the next couple of quarters?

Two places on the Mid-America, in Seminole pipe and the Dixie pipe and largely, really, you saw this come through in a couple places. Recoveries up in the Rockies were less, so we had less volumes coming down out of the Rockies. And so that really affected Mid-America Seminole. But then the other thing that impacted, if you would, Mid-American Dixie was just the milder winter compared to the winter of 2013-2014. That was the bulk of the difference in NGL volumes.

And on the margin front, what contributed to the out-performance there, mostly?

Just on some of the -- just spreads, regional price spreads.

And then on ethane exports, I know you all probably don't want to comment on individual off-take. But SABIC recently signed a 10-year deal for an unidentified amount. There's been a long gap between announcements and projects here, in off-take agreements. How is that progressing, in terms of filling out the remaining capacity at Morgan's Point? And is there scope for expansion there over the next couple of years?

We've got about 80% of it done. We continue to work it. I had some consultant that told me that his calculation said that crude oil had to be $85 for us to sell any more. I may had offered to bet him about $50,000 we'd have it sold out by the time it came online and I'm still willing to make that bet.

Your next question comes from the line of John Edwards with Credit Suisse. Please go ahead.

Jim, listening to all the opportunities you're talking about through storage and trading and such, I'm just wondering if you could give us an idea of what the contribution was this quarter, from perhaps trading around your storage and assets? And offsetting how much, say hit you were taking from commodity prices?

I don't have a clue, John. We'll get back to you. But we never used the word trading. We do optimize our system with our marketing group.

Your next question comes from the line of Brandon Blossman with Tudor, Pickering, Holt & Company. Please go ahead with your question.

Big picture M&A, can you guys briefly comment on what you're seeing out there? And if your thoughts have changed over the last three or four months at all, in terms of what may or may not be interesting for you?

We're seeing probably everything you're seeing. There are assets out there, I'm not sure how attractively they're going to be priced. There are a lot of firms, a lot of private equity, a lot of, frankly, some MLPs, that don't have much of a way to grow beyond doing acquisitions and so they're going to be probably actively competing for those. With respect to our outlook for participating in M&A, we just did a big deal. Oiltanking was a $6 billion transaction that we closed in February this year. So we won't say that we'll never do one. But when we do an acquisition, they tend to be things that hit us from a strategic standpoint. Oiltanking was certainly an example of that. We have assets there. It fits in nicely with our export outlook. For any additional acquisitions, again, buying an entire company is very difficult for us, because of FTC issues and simply the fact that it's hard to find a company where we like all of their assets. There may be some assets that come up for sale that we'll take a look at, but hard to handicap what that is. Right now, our primary focus is on organic growth.

Okay. That actually is quite useful color and then good segue organic growth. You guys are obviously at least one of the leaders in liquids export solutions. Has the recent correction, the correction in oil prices, put a pause button at all on how your incremental project discussions? Or is it business as usual on that front?

Brandon, this is Tony. I'll take that. I think obviously, with the kind of correction that we've had, the magnitude of it and how quickly it happened, if you were thinking about backing some large export projects, you'd stop and take a pause. Think about where you think the spreads are going and probably spend a minute to think about where demand is going. But with that said, Jim said in his comments, what's clear with this downturn is that the U.S. has too much. I think in our opinion, the world understands that. So while we may be in for a pause, we feel very strongly that the U.S. is going to be more and more looked at as an exporting nation and we're going to make sure we're well positioned.

[Operator Instructions]. Your next question comes from the line of Faisel Khan with Citigroup. Please go ahead.

Just a few questions, first, just on the Seaway Loop that ramped up at the end of the year. Can you talk about how the operations are going so far, year to date? Are you running at full steam now in April? And are you maxed out on capacity?

It's going very well, Faisel. I don't know that we're maxed out, but we're at higher rates than we've been. I guess we're knocking on the door, aren't we? So yes, we're knocking on the door of being full-out. Flanagan South was looped, so we're seeing a lot of Canadian crude. And with all the inventories in Cushing, we're starting to see people wanting to make their way to the Gulf Coast.

Okay, fair enough. And I figured -- are you required to keep a certain amount of spot capacity for walk-up shippers or--?

Yes, I think the rules are 10%.

And then just on the NGL equity marketing volumes, those numbers seem to be bouncing around quite a bit from quarter to quarter, especially sequentially. Can you talk about what's going on with those volumes, sequentially from fourth quarter to first quarter?

On the NGL equity volumes, really, what we're seeing there were really two things happening. We saw higher equity NGL production from our Louisiana and plants in South Texas. But then we saw lower volumes from the plants from the Meeker, Pioneer and San Juan plants. And if you would, that's both with respect to, really, sequentially. But also coming in and looking at first quarter 2015 versus first quarter 2014. And I think some of that just gets back to, what are the regional spreads in the Louisiana plants and the Texas plants are just closer to market. So they've got a little bit better recovery rates.

And let me add to what Randy's saying is, in a lot of our plants -- and Randy's right -- it's more difficult in Rockies plants, but the plants down there on the Gulf Coast, if a producer has elected conditioning and we may elect to step in and recover that ethane against our variable cost, which would show our equity production going up.

Okay. Does the producer make that decision or do you guys make that decision?

They'll make the decision to go into conditioning mode. We'll make the decision to step in and extract it in our [indiscernible].

And so Faisel, one of the things that you saw this quarter was, Yoakum was pretty much in full recoveries for substantially all the quarter, where that was not the case in the fourth quarter.

Okay, right. That's right. I forgot about that. And then just going back to Matt's question on the NGL pipeline storage business and the increase in margin there. Isn't that just the Oiltanking acquisition that explains most of that increase? Or am I missing something?

Faisel, that was part of it. That was a big part of it. But you also had -- that was probably the biggest part of it.

And then just going on to the onshore pipeline and services business, the ramp-up in volumes in the Rockies, I guess the Jonah gathering system, going to 1.6 a day from 1.5 a day. What's going on with that? Was there some downtime last year? Or was there something else that's going on in the growth in that segment?

We're going to get back to you on that one, Faisel.

Faisel, it's Randy. I'll get back to you on that, okay?

Okay. Fair enough. And then just on the petrochemical and refined product side, just with the Beaumont refined product export terminal ramping up. Can you talk about the volumes that are coming through that system, year-over-year, since you've been operating that terminal? Has it been pretty volatile? Or are you seeing a steady amount of cargo moving across that terminal, on a regular basis?

This is R.B. Herrscher. So we started up in May. We were pretty much sold out in August, but that's on a take or pay. The actual volumes across the dock had been steadily increasing. We're up in the range of 3 million barrels a month across the dock and we have room to continue moving up from there.

So what's the ultimate capacity of the export dock?

You could figure in the range of 5 million barrels a month.

Okay. And right now, you're running at about, you said 3 million, I guess.

We're running about 3 million, but it's take or pay agreements.

Okay. Understood. Thanks for the time, guys. Appreciate it.

You're essentially sold out, aren't you, R.B.?

Yes, we're sold out. We're sold out.

Your next question comes from the line of Darren Horowitz with Raymond James. Please go ahead.

Jim, just two quick questions, I want to go back to your comments around the movements of crude oil south and Seaway becoming more of a conduit for Canadian barrels. I'm just wondering -- and I know it's tricky to do -- but do you have a sense for what you think the margin capture opportunity could be, from blending and logistically optimizing the movement of those barrels? What I'm trying to get at is -- and maybe this is a question for Tony -- how pronounced do you think crude oil grade quality dislocations could become? Or how much pressure you think, in the Gulf Coast, the cash market for physical barrels could experience over the next couple months? And what that could mean for you logistically?

Yes, I'm going to disappoint you with my answer. But there are so many variables. You can start with the obvious one and that's Brent to WTI spreads that would impact that. It's really, really very difficult to say. So what your view is on Brent and WTI, you can start from there and dial knobs after that.

Yes. Okay. And then final question from me, just more on process condensate movements and I know this is the tricky one, I'm sure, to answer as it is to ask, but with additional Rancho capacity coming online, like you said, in July and movements more from West and South Texas out of Texas City. You've got, theoretically, I think the opportunity for even more capacity to move physical product, maybe even as far east at Beaumont. So I'm thinking, could there be upside to 13 million or 14 million barrels, by the end of this year? And what more capital do you need to spend, in order to really leverage that?

I think we're spending the capital now, Darren. I would hope it's as big as you say. I don't know what the absolute upside is, but we obviously believe there's upside. We could have done a lot more, had we not had the constraints, which was Rancho 1. Once we had Rancho 2 in place, I think, Robby, we've been spending the money at the docks to be able to load more. There is a tank issue. We put a couple of new tanks in service. So by August, we're going to be able to load more cargoes.

Your final question comes from the line of Helen Ryoo with Barclays. Please go ahead with your question.

Question on your new processing plant in Delaware Basin. So what's the cost? And maybe could you talk about the contract? Is it more POP and acreage dedication type of contract? Also, follow-on is, do you have an expectation when that plant will be filled up?

This is Jim. My expectation is always that it's full the day it comes up. I think we're -- we got enough gas that, if we don't get any more, we've got a very good project, it's fee based. And OXY, of course, is a large producer out there and they're our partner. And it comes on in mid next year.

And with respect to the cost, we don't generally break out costs for individual projects.

And is it a more acreage dedication type of contract? Or are they committing certain level of minimum volume?

I think there are minimum volumes on this one.

And then on the Aegis open season, so I guess you have currently like 275 committed on 400 capacity. Is the open season to fill up the remaining capacity? Or is there a possibility that you would -- depending on the level of demand, you may increase -- could the capacity go over 400? And if so, what kind of additional capital needed to get there?

This is Daniel Boss. This open season involves some expansion capital. So we're looking at installing some additional main line pumps to several locations along the pipeline. So we had an additional second open season in late 2013, for the remaining capacity, from phases 1, 2 and 3. So this is actually incremental to what we've done before.

Okay.

What will your total capacity be, Daniel?

Total capacity, once the project is completed will be just shy of 400,000 barrels per day.

And the additional capital you'd need to spend after the open season is to bring it to 400? Or is it -- bring it beyond 400?

Yes, this brings it to approximately 400, depending on the level of interest we receive. So if we receive enough interest, we'll get to the max pipeline capacity.

Okay. And is the additional spend pretty minimal amount?

It's not too bad. And a little color on what Daniel was saying. Typically, we don't go out for an open season unless we know there's interest for it.

And then just finally, on the LPG export contract, could you just remind me if you were able to add new contracts? Since the crude correction we've seen? And also, as it stands today, with your expansion coming, do you have some capacity to do spot business? And if so, compared to like your long term contracting rate and spot, are you able to gives us color on the difference in that margin? Is it like 2x, 3x? Any color around that?

Right now, if you look at what we consider our operational capacity, I think for the next two or three years, we're sold out. Right, Al?

Correct. We're sold out through 2017 and we're probably 80% in 2018.

And when we say we're sold out, we sell to our operational capacity. And then as we get closer to the month, if we feel comfortable that we may have extra capacity that we would then have available for spot.

Okay. And the spot margin versus these long term or multi-year contract, are you able to give color on how--

Right now, we like our long term contracts.

Okay. And the fact that you are sold out through three years, up to 2017, were these sold out prior to crude correction? Or were you able to sell out more capacity after it came down?

Yes, we're continuing to sell our capacity. We had the through 2017 capacity sold out prior to the correction. But we're continuing to sell 2018 forward, all the way to contracts to 2024. And we're growing our business in butanes, which we did with this expansion, giving us greater opportunity to move butanes across the dock, in addition to propane. So we're adding volume to our exports.

I would like to turn the call back over to Randy Burkhalter for any further remarks.

Brent, thank you. I think that's the end of our remarks. And so Brent, if you don't mind, would you give our listeners the replay information, before we close the call?

Certainly. To access the replay for today's conference, please dial 855-859-2056, if dialing from the United States or 404-537-3406, if dialing internationally. The conference code for this call is 25026446. Thank you.

I was going to say thank you, Brent and that concludes the call. We thank our listeners for listening to our call today and have a good day.

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