Enterprise Products Partners L.P. (EPD) Q1 2015 Earnings Report, Transcript and Summary

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 $85 million, to $695 million, compared with the first quarter of last year. Gross operating margin from our natural gas processing plants and NGL marketing business declined $109 million, primarily due to lower gas processing margins and sales margins. More of the LPG export volumes loaded this quarter were contracted under long term, fee-based agreements, compared with some higher margin spot volumes in the first quarter of 2014. Equity NGL production declined 2%, while fee-based natural gas processing volumes increased by almost 2%, compared with the first quarter of last year. In general, we saw lower volumes from our processing plants in the Rockies that were largely offset by higher volumes from our South Texas plants. Gross operating margin from our NGL pipelines and storage business increased $38 million or 13%, to $328 million for the quarter, with $21 million of this increase coming from the LPG export terminal on the Houston Ship Channel and related pipelines. Gross operating margin from our export terminal included $15 million associated with the Oiltanking transaction, with the remainder of the increase due to higher LPG export volumes. We expanded our LPG export capacity by 1.5 million barrels per month at the end of March. And we're on schedule to add another 7.5 million barrels per month of capacity by the end of this year, bringing total LPG export loading capacity to 16 million barrels a month. Gross operating margin from our NGL fractionation business declined $14 million compared to the first quarter of last year, primarily due to lower revenues from product blending. Gross operating margin from the onshore crude oil pipelines and services segment increased $54 million or 34%, to $214 million. Total onshore crude oil transportation volumes were a record 1.4 million barrels per day for the quarter, 10% higher than the first quarter of last year. Gross operating margin for this segment included $25 million from assets that were part of the Oiltanking acquisition and a $23 million increase from our ownership interest in the Seaway crude oil pipeline. The new Seaway Loop pipeline began commercial service in December of 2014. Our petrochemical and refined products services -- $44 million increase in gross operating margin, to $175 million for the quarter and that's a 34% increase over the first quarter of 2014. The TE Products pipeline system reported a $26 million increase in gross operating margin for the first quarter, compared to the first quarter of last year, due to lower operating expenses and higher revenues. Our refined products marine terminals at Beaumont and the Houston Ship Channel reported a $19 million increase in gross operating margin over the first quarter of 2014. These assets include a marine terminal in Beaumont that we reactivated in May of last year and marine and dock facilities associated with the Oiltanking transaction. Our propylene fractionation business reported a $15 million increase in gross operating margin, primarily due to higher sales margins and volumes. The indicative spread between refinery grade and polymer grade propylene was up 8% this quarter, compared with the first quarter of 2014. Gross operating margin from the offshore pipelines and services segment increased $7 million, to $46 million for the quarter, primarily due to the SEKCO Oil Pipeline, which began operations in July of last year. We continue to believe our diversified fee-based integrated system of assets positions us to succeed in a challenging commodity price environment. Our financial flexibility and healthy distribution coverage continues to provide a margin of safety for our investors, with average distribution coverage greater than 1.4 times and approximately $7 billion of retained cash flow over the last five years. We have clear visibility to growth, with over $6 billion of announced projects under construction that are targeted for completion between now and the end of 2017. These fee-based projects are supported by long term customer commitments. As I mentioned last quarter, we're not lacking for growth opportunities, given our active list of announced projects and the backlog of projects that are commercial team is still pursuing. And with that, I'll turn the call over to Jim.

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 new agreements, like those in the Eagle Ford. And we have other ways to make money in a low and volatile ethane price environment. With our access to natural gas residue pipelines, generally several at each plant and the flexibility we have for recoveries, we have significant capability for ethane rejection and re-injection. Also, some of our units can burn natural gas, ethane or even a combination, whichever is cheaper. We can and do make these types of changes daily, if that's what the market gives us. Further, with our connectivity to supplies and markets across the country and our infrastructure, we're able to participate in [indiscernible] regional price discrepancies, which during periods of high volatility are increasingly significant. Low ethane prices are caused by having too much, which is why we're now building an ethane export facility. Propane producers enjoyed a windfall last winter, again because of the cold winter. However, since then, propane prices have fallen dramatically and the U.S. is now dealing with an inventory overhang that is some 25 million barrels above average. Different than ethane, propane rejection back into the gas stream is not an option, so this low price propane still moves in our pipes and fractionators, stored in our caverns and moved through our distribution pipelines, to petrochemical markets, for example, where demand generally picks up with low prices. Export markets are more robust when the U.S. has depressed propane prices, so any spare capacity we can make available at our docks increases in value. With the rapid price downturn, markets are volatile, sometimes turned upside down, between regions, months and seasons. This kind of dislocation can add significant value to participants that have the ability to store barrels through this chaos. For natural gas, storage gives us the opportunity to buy prompt, store and then sell forward at higher prices, adding value to our assets. For ethane, we have significant ability to store ethane when it's priced below its forward values and capture the contango. As importantly, because we have the ability to move and store both ethane and natural gas, we can and do capture the orb, not just between months but also between the two commodities. These are just BTUs that we convert to their highest value, either tomorrow or even next winter, whichever is greater or both. Similarly, propane is also stored for better days, currently at record volumes, so our storage business at Mont Belvieu, Hobbs and Hattiesburg is doing very well. These capabilities are the same for butane, for natural gasoline, for petrochemicals and refined products. Finally, crude oil, which currently the whole world is focused on, our crude has seen good gains the last few weeks. It's still down greater than 40% from where it was just one year ago. So what's the upside of low crude prices for Enterprise? The obvious one is the steep contango that is currently in the curve, which adds significant value to our assets, as our customers store in order to capture the higher future value. In addition, because WTI is literally some of the cheapest crude in the world, it wants to move toward the Gulf Coast, where it can displace imports in refineries, which benefits both our pipelines and our terminals. Also, with the Enbridge Flanagan South expansion now complete, Canadian movements are very good right now, which again, is good for our Seaway pipeline and our Seaway docks and terminals. Also, our processed condensate business is growing. Again, good for our assets and we're continually adding assets [Technical Difficulty] be able to export much more of not only processed condensate but also Canadian crude. For crude, we also have all the tools and are taking advantage of blending opportunities. And finally, we're integrating the Oiltanking assets into ours, which is going very well, which allows us to offer new services to an expanded customer base. Strong storage spreads, regional dislocations, cross-commodity exchanges, product rejection and dual fuel capabilities are a few concrete examples of how we think about making money when the markets change like they have in the last six months. We're very comfortable that we can make good returns and continue to grow in this kind of the cycle. From a project perspective, we're in the middle of an open season to expand our Aegis pipeline. This open season recognizes the fact that we continue to work with new project sponsors on connections and extensions to Aegis and long term supply arrangements. We also have our new Permian NGL assets under construction in the Delaware Basin and today we announced a joint venture with OXY to develop another $150 million cryogenic processing plant in the Delaware Basin, to be in service mid-2016, adding to our presence in this basin and offering customers, through our assets, access to Mont Belvieu. We recently completed an LPG export expansion at Enterprise hydrocarbons terminal, with another larger expansion coming online by year-end. We'll nearly double our export capacity in 2015, to 16 million barrels a month. Construction on our ethane export facility at Morgan's Point and the Houston Ship Channel is underway and we look forward to a mid-2016 completion. In crude oil, our new Rancho 2 pipeline will be complete in July and with Flanagan South complete and high Cushing inventories -- inventories high, Seaway is running at the highest rate to date. We're also nearing completion of our crude oil distribution system on the Houston Ship Channel. We remain very positive about the potential for significant process condensate exports and what that means to our assets. In addition, we continue to work with potential shippers on our major oil project pipeline, from the Midland Basin to ECHO and remain confident that we'll be successful. Our PDH facility is under construction and is progressing as expected. Our petrochemical team's also working on other investments that we think will be a good fit. On refined products, we're pleased with how this business is performing and we're confident in its long term fundamentals, which are pretty simple. Demand is falling in the U.S. We have a rapidly growing supply base. Demand is growing in other parts of the world. We think the U.S. is becoming more of the substantial exporter of refined products. We're confident we're going to have significant opportunities in this area. In closing, without a doubt, 1.4 coverage in this environment should be proved that the sky isn't falling, at least not for Enterprise. Our businesses are integrated such that we find opportunities regardless of the environment. We have new projects working in every business and we're going to continue to advance the ball in this part of the cycle. This cycle proves that the U.S. has too many hydrocarbons. Enterprise continues to do our part in finding new markets for U.S. production. We've said over and over, we're not only focused on the supply side of the equation; we're also focused on the demand side. We're the leader in exporting propane. We're creating a system to deliver ethane to new and expanded ethylene plants. We're constructing a plant that will turn propane into propylene. We're building a facility to export ethane. We took the lead in getting a ruling to export processed condensate. With our partner, Enbridge, we're positioned to export Canadian crude oil through our Seaway docks. We're expanding our capability export refined products and soon we will own all or a part of deepwater docks from Corpus Christi to Beaumont. We're well positioned to support growing U.S. production and finding markets. If you think about it, every expansion in the midstream sector and the petrochemical sector, is actually a bet on the success of U.S. exploration and production. The fact is that our refining industry is now a net exporter, because of the success of U.S. exploration and production. What's ironic is that there are only two countries in the world that are living under restrictions that prevent them from freely exporting crude, Iran and the U.S. and news reports suggest that soon, there may be only one. Ultimately, we believe that could undermine the positions of those industries that are prospering because of the bets they're making on U.S. E&P. If U.S. E&P is the foundation of your success, then [indiscernible] markets will ultimately undermine your foundation. Ethylene manufacturers only have to remind themselves that 40% of U.S. NGLs come from associated gas from crude oil and condensate production. And then finally, if you're waiting for us to say something about Mike retiring, you're too early. With everything we're working on, he's got a lot on his plate between now and the end of the year. Also, given the fact that he's the best I've ever known at negotiating acquisitions and given the current environment, I hope he knows he's subject to recall. With that, I'll turn it over to Randy.

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 makeup right period. The recognition of previously deferred revenues was $20 million for the first quarter of 2015, which included $17 million recognized from shippers on the ATEX pipeline. Depreciation expense for the quarter increased $44 million, primarily due to the Oiltanking acquisition and from new assets placed into service. G&A expense for the first quarter of 2015 decreased by 7%, to $49 million, compared with -- to last year. Interest expense increased $18 million, to $239 million, for the first quarter of 2015, primarily due to higher average debt balances. Total capital spending in the first quarter of 2015 was $2.3 billion, which includes $1.4 billion of equity consideration to complete the acquisition and merger of Oiltanking, which closed in February and $51 million of sustaining capital expenditures. Sustaining capital expenditures this quarter were lower than anticipated, due to inclement weather in various parts of the country in the first quarter and a couple of larger projects that are scheduled for later in the year. At this time, we do not have an update for sustaining capital expenditures, so we still expect it to come in around $380 million for 2015, although that could be a little high. We will provide an update on the second-quarter earnings call. In terms of capitalization and leverage, adjusted EBITDA for the 12 months ended March 31, 2015, including EBITDA associated with Oiltanking for that period was $5.3 billion. Our consolidated leverage of debt principal to adjusted EBITDA was 3.9 times for the 12 months ended March 31, 2015. That is after adjusting for 50% equity treatment for the hybrid debt securities. At March 31, 2015, we had consolidated liquidity of $3.7 billion, which included available borrowing capacity under our credit facilities. In addition to the $295 million of retained distributable cash flow in the first quarter, we raised approximately $468 million through our ATM, our distribution reinvestment plan and employee purchase plan programs. This included approximately $100 million of net proceeds from affiliates of privately held EPCO through the ATM program. These affiliates have also indicated they expect to purchase an additional $50 million of common units through the distribution reinvestment plan on the May 7 distribution date. As a reminder, purchases through the dividend reinvestment plan are at a 5% discount off the average of the daily highs and lows, for the five trading days preceding the payment date. At March 31, 2015, the average life of our debt was 13.7 years, using the first call date for the hybrids and our effective average interest cost was 4.7%. With that, Randy, I think we're ready for questions.

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.