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Enterprise Products Partners L.P (NYSE:EPD)

Q3 2013 Earnings Call

October 31, 2013 10:30 a.m. ET

Executives

Randy Burkhalter – Vice President, IR

Mike Creel – Chief Executive Officer

Jim Teague – Chief Operating Officer

Randy Fowler – EVP and CFO

Leonard Mallett – Group SVP, Engineering

Analysts

Brian Zarahn – Barclays Capital

Darren Horowitz – Raymond James

T.J. Schultz - RBC Capital Markets

John Edwards – Credit Suisse

Michael Blum – Wells Fargo Securities

Mark Reichman – Simmons & Company

Operator

Good morning. My name is Molly. And I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners’ Third Quarter 2013 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you.

I would now like to turn the call over to Randy Burkhalter, Vice President of Investor Relations. You may begin your conference.

Randy Burkhalter

Thank you, Molly. Good morning everyone and welcome to the Enterprise Products Partners conference call to discuss results for the third quarter. Our speakers today will be Mike Creel, CEO of Enterprise’s General Partner; followed by Jim Teague, Chief Operating Officer; and Randy Fowler, Executive Vice President and CFO. Other members of our senior management team were 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 Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by, and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

With that I’ll turn the call over to Mike.

Mike Creel

Thanks, Randy. This quarter we had record NGL and crude oil transportation volumes, record NGL fractionation volumes and record LPG export volumes that led to solid results. These increases were primarily driven by growth in NGL and crude oil production in the Eagle Ford shale, higher crude oil volumes on Seaway Pipeline and increased propane loadings at our export facility. As a result, gross operating margin was $1.2 billion for the third quarter of 2013 compared to $1.1 billion for the same quarter of last year.

Adjusted EBITDA was $1.1 billion for the third quarter 2013 and 2012. Distributable cash flow increased to $908 million in the quarter from $743 million in the third quarter of 2012. Included in distributable cash flow were proceeds from asset sales and insurance recoveries of $57 million this quarter and $11 million in the third quarter 2012. Distributable cash flow for the third quarter of last year also included a $24 million benefit from the settlement of litigation and a reduction of $70 million from a loss on the settlement of interest rate hedges associated with our issuance of senior notes in August of 2012.

Excluding these items, distributable cash flow for the third quarter of 2013 increased 10% to $851 million and provided 1.4 times coverage of the cash distribution declared with respect to the quarter.

We recently declared a $0.69 per unit cash distribution with respect to the third quarter, which is 6.2% higher than the distribution paid with respect to the third quarter of last year. This distribution will be paid on Thursday of next week to unitholders of record as of the close of business today. And it represents the 37th consecutive quarterly increase in our cash distribution per unit.

We retained $286 million of distribution cash flow for the quarter and over $900 million for the first nine months of this year. Retained distribution cash flow is available to reinvest in the growth of the Partnership and reduce our reliance on our capital markets. Approximately $250 million of year-to-date retained distributable cash flow are from proceeds from the sale of non-core assets that were earning a relatively low returns on capital. We intend to reinvest these proceeds in projects with higher returns on capital to further increase EBITDA and distributable cash flow.

The NGL Pipeline & Services segment reported gross operating margin of $640 million for the quarter compared to $616 million for the third quarter of last year. Gross operating margin from our natural gas processing and related NGL marketing business decreased by $59 million, primarily due to lower processing margins from our Rocky Mountains natural gas processing plants and lower proceeds from hedging activities. Higher natural gas prices and lower ethane prices led to a decrease in gathering and processing volumes across all of our operating areas in the Rockies, as producers have slowed drilling in the region.

Lower processing margins also resulted in periodic ethane rejection at certain of our plants, which reduced equity NGL production. Partially offsetting the impact of lower natural gas processing margins was a $30 million increase in gross operating margin on fee-based processing activities. Fee-based natural gas processing volumes increased to 4.7 billion cubic feet per day this quarter, from 4.5 billion cubic feet per day in the third quarter of last year.

Gross operating margin from our NGL pipelines and storage business increased $36 million or 18% quarter to quarter to $231 million. Our South Texas NGL pipeline system contributed $18 million to this increase, primarily due to a 158,000 barrel per day increase in transportation volumes on increased Eagle Ford shale production. Our LPG export facility and related channel pipeline reported an $18 million increase in gross operating margin on a 255,000 barrel per day increase in propane volumes.

We increased the refrigeration capacity of our LPG export facility in March of this year and we are now loading an average of 7.5 million barrels a month of propane. NGL pipeline transportation volumes were a record 2.9 million barrels per day this quarter, exceeding the record set last quarter of 2.7 million barrels per day.

Our NGL fractionation business reported record gross operating margin of $116 million for the third quarter this year. This 69% quarter-to-quarter increase was primarily due to increased volumes at our Mont Belvieu fractionators. Our sixth and seventh NGL fractionators at Mont Belvieu began service in October of last year and September of this year respectively.

Gross operating margin from the Onshore Natural Gas Pipelines & Services segment increased to $213 million this quarter from $184 million for the same quarter of last year. The majority of this increase was due to an increase in firm capacity revenues from our Texas Intrastate Pipeline system, which benefitted from increased production from the Eagle Ford shale.

Our Onshore Crude Oil Pipelines & Services segment reported gross operating margin of $146 million for the quarter, compared to $118 million for the third quarter of last year. This $28 million increase was primarily due to higher pipeline volumes, partially offset by lower margins from our crude oil marketing activities.

Total onshore crude oil pipeline volumes were a record 1.3 million barrels per day this quarter, up 53% over the third quarter of 2012. Gross operating margin from our South Texas crude oil pipeline system increased $51 million, primarily due to a 137,000 barrel a day increase on our Eagle Ford pipeline that began service in June of last year. We also had an $18 million increase in equity income from our investments in Seaway and Eagle Ford joint venture pipeline with Plains, primarily due to a combined 234,000 barrel a day increase in volume.

Partially offsetting these increases in gross profit margin was a $41 million decrease from crude oil marketing due to lower sales margins attributable to tightening price differentials in the markets we serve.

Our petrochemicals and refined product services segment reported gross operating margin of $117 million for the quarter compared to $182 million in the third quarter of 2012. Gross operating margin from our propylene business decreased $28 million due to lower sales margins and costs associated with the plant turnaround. Our marine transportation and other services business had a $26 million decrease in gross operating margin, primarily due to the $24 million benefit from a legal settlement that we recorded in the third quarter of last year.

Our refined products pipelines and related services had a $4 million decrease in gross operating margin largely due to reduced volumes and higher pipeline integrity expenses associated with the preparation of the segment of that pipe that is being converted to ethane service as a part of the ATEX pipeline project.

Our large portfolio of assets continue to provide opportunities for growth and expansion. This year we put $1.5 billion of major growth capital projects into service and we expect to complete another $925 million of projects in the last quarter of this year. Next year is going to be a big year for us with approximately $4.5 billion of growth capital projects expected to come online and of that approximately $3 billion is planned to begin service in the first quarter of next year.

In 2015, we have another big year with $3 billion of capital projects already slated to begin operations. All of these projects are in various stages of construction and are supported by customer commitments ranging from five to 15 year contracts. While some of the projects will have a volume ramp up period such as the ATEX and the Aegis projects, other, such as our NGL fractionators are fully contracted when they begin service.

Since 2010 we have put approximately $8 billion of capital projects into service. Over that same period we’ve seen our gross operating margin grow 45% from $3.25 billion in 2010 to $4.7 billion for the trailing 12 months, that is, September 30, 2013. The contribution from these new assets was a large contributor to the increase in gross operating margin over that time.

Given our sizeable backlog of organic projects and their significance to the future growth of our partnership, execution and timeliness is critical. We are pleased with the efforts of our engineering and commercial groups and ensuring the successful execution of these projects, completing them, and with very few exceptions, they were brought in on time and on or under budget.

Now, before I turn the call over to Jim I’d like to close by saying that we’re pleased with the solid results generated by our businesses in this quarter and this year. We are excited about our future and confident in our team of dedicated employees and their ability to continue to execute our growth plans and find new opportunities.

And with that, I’ll turn the call over to Jim.

Jim Teague

Thank you, Mike. As Mike mentioned, we continue to deliver. Our results continue to show the strengths of having a balanced portfolio that includes natural gas, NGLs, crude oil, refined products, petrochemicals and includes the benefits of our growing exposure to global markets.

Typically we always face some type of price pressure in some part of our business, or I should say margin pressure. And that’s true today in our petrochemical segment to some extent and definitely in our processing segment. But because of our balance across multiple commodities we continue to prosper in an industry that’s anything but business as usual.

The explosive growth of the U.S. shale hydrocarbons is now changing not only the U.S. but the global landscape and we’re determined to be a substantial player in this evolution, not only in LPG but across all of the hydrocarbon commodities. As Mike mentioned, the build out we started in the Eagle Ford three years ago is virtually complete. We’ve completed nearly $4 billion of natural gas, natural gas liquids and crude oil projects in what we now all recognize as one of the hottest plays in the country.

Kind of interesting how we did this, we started with a solid base of natural gas and NGL assets that supported conventional production in South Texas for literally decades. We moved to add key bridge projects, and those are projects that fill the available plant capacity we had and then we built new assets supporting all of the commodities this play has to offer. The build out included crude pipelines, natural gas pipelines, NGL pipelines, related pipeline compression and pumping, 200,000 barrels a day of fractionation at Mont Belvieu and 1.1 bcf a day of processing capacity. That processing capacity is your Yoakum plant. And over 140,000 barrels a day it may be the largest NGL producing plant in North America.

In addition, and keeping with our link and leverage approach, all of these Eagle Ford assets feed other enterprise assets in Mont Belvieu and they’re available to support a growing list of projects for new demand, some outside of the U.S.

We recently brought our Frac 7 train on at Mont Belvieu and we expect Frac 8 will be up and running before the end of the year. I’ve been quotes as saying, we’re not going to build any more fractionators but given the list of customers that continue to call, the folks that run our fractionation business has convinced us to seek permits for two additional fractionators; and that’s an announcement that says we’re building them, it’s just that I’m saying that we can.

And our PDH plant, this project provides additional balance to our portfolio. Site work is underway. Long lead time equipment has being ordered and Leonard Mallett has committed that this plant will be up on October 1st, 2015.

Regarding the extensive pipeline build out we have under construction. The build out of what we refer to as our Western pipelines, that’s Texas Express Front Range and our mid-America Rocky Mountain expansion, is progressing. This morning we announced that we’ve begun service on a new 580 mile Texas Express NGL pipeline. We expect the Front Range pipeline to begin service in the first quarter and the mid-America Rocky Mountain expansion should be online the 1st of January.

I have to say, we have partners in two of these projects that we’re quite proud to be aligned with. In Texas Express, our partners are Anadarko, Enbridge and DCP. In Front Range, our partners are Anadarko and DCP. We’re constructing this pipe and we’ll operate both of the joint venture pipelines. And every one of these projects are backed by partner demand fees [ph] and the volume will be ramping up over the next three years.

Our ATEX pipeline will be up in the first quarter of 2014 and as most of you know it is badly needed by the Appalachia producing community. This project is supported by long term contracts that ramp up over time. Given the recent problems caused by excess ethane in the region, we wouldn’t be surprised to see our flows exceed the contracted volumes as producers look for ways to get their wells flowing. We will begin land filling this project in December.

And the last regulated project I will address is our Aegis ethane header. This is another project, which will deliver a whole new level of service to our petrochemical customers, providing purity ethane to the ethylene crackers all along the Gulf Coast, coupled with our South Texas ethane pipeline and anchored by our assets at Mont Belvieu and supplies from ATEX, Seminole, our Hobbs fractionator, Louisiana and South Texas, will be providing reliable supplies to ethane to petrochemical facilities through a header that literally stretches from Corpus Christi to the Mississippi Corridor.

We have access to over 600,000 barrels a day of ethane, all of it accessible to Mont Belvieu to support this ethylene market, and by my count that is over double that of the next largest midstream in this space. The Aegis pipeline is the kind of solution that ensures the reliability and the efficiency needed to encourage new markets for growing shale hydrocarbons and I have to give credit to Lynn Bourdon whose idea of building an ethane header he had three years ago.

Regarding -- crude oil to Seaway looping is progressing and will be up in mid next year. The Jones Creek extension goes from Freeport up to ECHO first part of January and the lateral to Beaumont-Port Arthur mid-2014. In addition to the 750,000 barrels of storage we currently have in service at ECHO, we will be adding 900,000 in the first quarter and we expect ECHO will be fully built out something north of 6 million barrels by early in 2015. In fact, we will start bringing on new tankage I think in October of next year and be bringing tankage on each month until it is built up in the first part of 2015.

We announced a crude oil distribution header earlier that we are building on the Houston Ship Channel. I am confident that no one is going to have access to the lighter crudes and direct access to refiners that we’ll have all along the Gulf Coast. Coupled with ECHO, the new pipe to Beaumont-Port Arthur and our access to water, you can expect that ECHO and its distribution system is going to play a key role in moving varying types of crude to the entire Gulf Coast. We are going to marry growing supplies from Canada to Bakken, Cushing, West Texas, Eagle Ford and imports into the largest refining complex in the world and we will also be able to export.

From ECHO we will have direct connectivity to every refinery in the Houston, Texas city area and through the Seaway lateral to the refineries in the Beaumont-Port Arthur area and we will have six docks with load and unload capabilities. The build out of our refined product export dock in Beaumont is moving nicely. We expect to be able to load distillate in early 2014 and it will be completely in service by the third quarter of 2014.

And finally LPG exports. We recently announced that we will be constructing a second LPG facility that will have export capacity of another 6.5 million barrels a month. Already the largest provider of LPGs for export from the U.S., when we finish this new dock and the expansion to our existing dock, we will have the aggregate capacity to load 16 million barrels a month at those two terminals. Our facilities are supported by more than 25 firm agreements, some of which extend out to 2024.

Similar to ethane, our access to propane supplies, more specifically low ethane propane supplies, is what really supports our export activity. With our history of loading over 400 million barrels of LPG, our extensive access to supplies, the market clearly has confidence in our capabilities and they have been very supportive of our expansions. There is a lot of noise in this space but obviously the market realizes that no one has our access to supplies, nor our track record. While others are busy considering and planning, we are busy signing up long term contracts with a solid customer base and expanding our facilities.

Finally, we continue to believe that our focus needs to be not only on the supply side of the equation but also the demand side. We have been successful in developing major supply projects as the shale plays develop. We’ve repurposed assets as flow patterns change and we continue to pursue solutions for new markets – with projects like our PDH plant, our ECHO terminal, our Aegis ethane header and our crude oil distribution system and last not least export capabilities for LPGs, refined products and crude oil. Creating solutions to support new demand is what we like to do and what we think differentiates us from others.

With that, I will turn it over to Randy.

Randy Fowler

Thank you, Jim. I would like to take a few minutes to discuss some additional income oriented items and liquidity as well for the quarter.

We reported net income attributable to Limited Partners of $592 million and earnings per unit of $0.64 per unit on a fully diluted basis for the third quarter 2013. Net income and EPU for the third quarter 2013 were affected by the following items: $15 million or $0.02 per unit on a fully diluted basis for non-cash asset impairment charges, $7 million or $0.01 per unit on a fully diluted basis for an adjustment to the Texas margin tax, expense accrual related to legislation passed in the second quarter 2013.

And finally, net income and EPU was also included $10 million or $0.01 per unit for gains from asset sales. Interest expense increased to $208 million this quarter from $200 million in the third quarter of 2012, primarily due to an increase in our average debt principal balance. Our weighted average cost of debt decreased to 5.3% for the third quarter 2013 compared to 5.7% for the third quarter 2012.

At September 30, our weighted average cost of debt was 5.2%. The provision for income taxes increased $17 million this quarter compared to the third quarter last year, primarily due to higher Texas margin tax expense accruals. Including in the provision for taxes this quarter was the $7 million adjustment to the Texas margin tax expense accrual related to the legislation that was passed last quarter.

Capital spending was $1.2 billion this quarter, included approximately $1.1 billion on growth capital, the majority of which was for ATEX and the NGL fractionators 7 and 8. We are on track to invest approximately $4.2 billion in growth capital this year, having invested approximately $3 billion in growth capital projects through the first nine months of 2013.

Sustaining capital expenditures were $82 million this quarter and $214 million for the first nine months of this year. We expect to spend between $300 million to $325 million in sustaining capital expenditures this year. This is slightly lower than our estimate that we gave at the beginning of the year while top-line integrity costs are expected to come in on budget at $153 million for the total year of 2013. Certain discretionary engineering projects have been proceeding more slowly than planned and will slip into 2014.

Adjusted EBITDA for the 12 months ended September 30, 2013 was $4.6 billion. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.6 times for that period, after adjusting for the 50% equity treatment for the hybrid debt securities. The average life of our debt at September 30 was 13.4 years using the first call date for the hybrids. And our effective average interest cost of debt at that time again was 5.2%.

During the third quarter, we received $299 million throughout our ATM dividend reinvestment plan and employee unit purchase plan programs for the first nine months of the year. We received $648 million from these programs, of which $460 million was through our ATM program. We also received $487 million from an underwritten equity offering back in February 2013. These programs in our retained DCF continue to provide us flexibility on our timing and size of offerings when we come to the capital markets.

Privately held EFCO was – has purchased $75 million of enterprise common units through the dividend reinvestment program this year and expects to purchase another $25 million of enterprise common units through the program for the distribution to be paid on November 7. This will bring our total purchases of enterprise common units to $100 million this year.

At September 30th we had consolidated liquidity of approximately $3.9 billion; that includes availability under our credit facilities as well as unrestricted cash.

With that, Randy, I think we’re ready for questions.

Randy Burkhalter

Okay, Molly, we’re ready to begin our Q&A.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Brian Zarahn with Barclays.

Brian Zarahn – Barclays Capital

Good morning.

Jim Teague

Good morning, Brian.

Brian Zarahn – Barclays Capital

I need you to provide some color on the new LPG export terminal. Perhaps, a range of cost, location options?

Jim Teague

I don’t think we ever say what it cost and we haven’t decided where we’re going to put it.

Brian Zarahn – Barclays Capital

Well, Jim, can you give us some options – you have a couple of options available where you may put it and maybe some – obviously, your access to Belvieu is important, anything on that would be helpful.

Jim Teague

It will be on the Gulf Coast. And, you know, we have pipeline capacity that will be able to access it. We should be able to access it. We should be able – where is Mandy – probably in the next couple of weeks, we’re going to be able to say where that plant is going to be built.

Brian Zarahn – Barclays Capital

Okay.

Jim Teague

I’m allowed to be upright.

Brian Zarahn – Barclays Capital

No. We’ll stay tent. On the – given the new projects, is there any update to 2014 expansion CapEx, I think the last update was about $3.5 billion to $4 billion.

Randy Fowler

Yeah, Brian, this is Randy. I think we’re in that same range.

Brian Zarahn – Barclays Capital

Okay. Just maybe in ’15 that number will be higher than initially thought. I guess and then anything on maintenance CapEx in terms of what you’re looking at for next year.

Mike Creel

You know, Brian, we’re going through our planning process now but, again, I think we’re probably going to be probably in the similar range of what we were for this year, you know, in the $325 million to $350 million range. Probably when we have our next quarterly earnings call for the fourth quarter, which will be, what, end of January beginning of February, we’ll be able to give you a better update at that point in time.

Brian Zarahn – Barclays Capital

Okay. And then could you – what’s your view on the – for Seaway the ALJ [Administrative Law Judge] ruling on the tariffs and what would be – and in terms of negative outcome scenario, what type of impact do you think that could have.

Randy Fowler

Listen, I don’t think we expect a negative outcome on that. You know we have gone through this process late last year, the FERC staff and the hearing had challenged these committed rates and we’re further petitioning declaratory order into the FERC to get them to essentially uphold their long-standing policy that they honor those committed rates they are entered into during open season. And we’re pleased with the response we got back from the FERC at the time. They basically said they uphold those rates. And then during the hearing and on the ALJ’s initial decision that really is a recommendation to FERC, surprisingly enough, I guess to us, she did again challenged the committed rates, so filed our refund exceptions to that as have others. We also, during that point in time, filed a motion for expedited treatment to get FERC to come out and say they honor those committed rates and I think the final paperwork will be in by the 5th and then we’ll see how long it takes the FERC to rule on that. But we’ve already heard from them once a positive ruling and we don’t expect otherwise.

Brian Zarahn – Barclays Capital

Okay. Thanks, Bill. And last one for me is, given your diversification, the high coverage and a large amount of projects coming online next year, how do you view any change in your current penny a quarter distribution bump.

Mike Creel

Gee, Brian, we just increased that last year at this time.

Brian Zarahn – Barclays Capital

But you keep spending money and you keep getting cash flow.

Mike Creel

I know. It’s a high class problem. As we’ve said before, we continue to look at what our projects are in backlog and we’re in a fortunate position of having a lot of opportunities and to the extent that we have a lot of construction opportunities and are able to fund some of that internally, we think it provides better long-term returns for our unit holders. But again, we look at that every quarter and try to assess what our internal needs are and what the appropriate distribution rate is.

Brian Zarahn – Barclays Capital

Thanks, Mike.

Mike Creel

You bet.

Operator

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

Darren Horowitz – Raymond James

Jim, I got a couple of questions for you. The first, I want to go back to your comments around the excess ethane situation in the Marcellus. To what extent do you guys think first production, outpatient takeaway capacity, but more importantly, how you see that evolving over the next year and what you think that does price? And where I’m going with this is I’m wondering whether or not that changes the way that you view those two competing “y” grade solutions getting done or does it give you more confidence in additional purity ethane commitments on ATEX?

Jim Teague

It’s the longest question I’ve ever gotten, Darren.

Darren Horowitz – Raymond James

It’s about 5 pounds of information in a 10 pound bag.

Jim Teague

Yeah.

Darren Horowitz – Raymond James

It’s the other way around actually.

Jim Teague

Right. Yeah. Okay. Let me see if I can remember. We’re going to short line [ph] building ATEX. And in December or later – so we should have that in service sometime in January but we think about end of January we’ve been delivering into Mont Belvieu. We’re going to start at, I think – we start out at about 70,000 barrels a day, in that neighborhood. And I don’t know if we’ll see more or not but what I said was, it’s not going to surprise me as these guys are having some issues up there. In regards to the two “y” grade pipelines. We – as you know – that’s kind of why I said, we file for two more permits for fractionators. If they bring those pipe down there is going to be more fractionation capacity available. In terms of price, 70,000 barrels a day of new ethane doesn’t help it at all.

Darren Horowitz – Raymond James

Yeah, okay. And then last question, just switching gears to your comments around the LPG export facility – and I recognize that you’ve got contracted commitments for that capacity but when you start thinking about what you’re adding as well as what competitors are adding, both, announced and proposed, when do you think we get to a point where the U.S. has ample export capacity to meet demand? And do you worry that we get to a point where supply additions start saturating Northwest Europe, Latin America, Asia and that diminishes the ARPU [ph] spread more so than it has and it really starts to impact propane pricing.

Jim Teague

Well, I worry about everything. You know, I think – we call it an LPG export facility for a reason. I do believe that LPG will be exported from the U.S. but I do believe that you’re going to see a lot more butane exports in the future then we’ve seen in the past. So, yeah, I think you – there’s a point that you’re going to be exporting butane rather than propane, but I’ll look at is I’ll look at it in a context of the total rather than product specific.

Darren Horowitz – Raymond James

Okay. Thanks, Jim.

Operator

Your next question comes from the line of Mark Reichman with Simmons.

Mark Reichman – Simmons & Company

I’ve got several questions, and good morning. Just to tag on to Darren’s question. I mean, in light of the increased export capacity being developed, I would be interested in your thoughts on the global LPG, NGL supply/demand balances and what do you think is the upper limit on demand to absorb growing U.S. exports of propane, butane and possibly ethane? And then secondary to that, how do you view the risks associated with investing in additional fractionation capacity knowing that a growing proportion of its output will be destined for export markets and does that change your investment considerations or investment criteria?

Jim Teague

Okay. Let’s talk first – you know, as long as there is a lot of crackers in other parts of the world using naphtha, and LPG can be exported from the U.S. at a price that can displace that. I think the demand is beyond what we would traditionally think it would be. Lin, is that right?

Leonard Mallett

That’s correct.

Jim Teague

Okay. So your other question of fractionation. You know, I didn’t say we’re going to build it. I said we’re going to be – we can if we choose to but, yeah, I always worry about fractionation capacity. I always hear, when we were doing deals at a penny in a quarter, so, yeah, we worry about it and we’re going to manage it.

Randy Fowler

Well, one of the things we did – hang on just a second – one of the things we did is we don’t just – you know we’re kind of like an airline at Mont Belvieu, we overbook, and we use our fractionation capacity throughout our system. So, when we manage our fractionation business we’re not managing Mont Belvieu, we can get our “y” grade at almost every fractionator we got and switch it between. So what we’re looking at is we’re running Hobbs, Shoup, Mont Belvieu and our fractionation in Louisiana. We run it as one big complex and that’s how we manage it.

Mark Reichman – Simmons & Company

Okay. So, I mean, you know, what I’m thinking about and I’m thinking that we’re not going to be building fractionation to support export demand. I mean, that’s kind of what I was getting at is as export demand claims a greater portion of the purity products and how does that impact – I mean, do you view international and domestic demand one and the same as long as you have fee-based contracts or as exports become a bigger part of the equation do you become a little more stringent in allocating dollars to fractionations? That was kind of where I was going with that.

Jim Teague

I will start off by saying I think export demand is real. I don’t think it’s specific to just LPG, we are building the export facility on retained products because we believe this market is evolving into a large export market. As in turn, I guess I look at demand as demand, I will flip and tell you – I would be very careful as a producer, so go back to the producing community, I would be very careful as a producer of hanging head on just exports. That’s why we built ours on the Gulf Coast and in combination with our ability to distribute domestically.

Exports are going to be – you are going to have times when exports slow down, it’s an arbitrage game. So what we offer producers and consumers is we are going to – that product is going to flow regardless of what the demand application is for that product.

Mark Reichman – Simmons & Company

I see and then just last question and I will get back in the queue. It seems the E&P industry is kind of moving from a point where multiple speculative shale plays were being probed and tested a few years ago to where today, a handful of leviathan plays generate a lion share of the production growth and returns. So given the narrowed breadth of the unconventional resource narrative, how does this impact both the competitive and investment landscape going forward for midstream operators?

Unidentified Participant

I guess I will take that one. This is Tom [ph]. It is true that new onboard kind of shale plays have slowed down but it’s also true that we are continuing to get more and more off the shale plays that we have and be much more efficient both from a cost standpoint and what we get in per well. So if your concern is that the shales are going to short of figure out if you will – that’s not what we believed it all.

Mark Reichman – Simmons & Company

So I think it has played to your strength for those that are already in those big plays might have some implication for consolidation down the road.

Unidentified Participant

You mean relative to the E&P players?

Mark Reichman – Simmons & Company

To the midstream operators?

Mike Creel

Mark, I think you are seeing more MLPs being formed but as always it’s difficult to do MLP combinations. Particularly when more and more of these have publicly traded GPs and frankly, as far as we are concerned, we’ve got better places to put our money.

Operator

Your next question comes from the line of T.J. Schultz with RBC Capital Markets.

T.J. Schultz - RBC Capital Markets

Just one follow up on LPG marine terminals, you have the flexibility to add ethane export services, as that market develop – if you could just expand on the interest you are seeing in ethane exports or are you at the point of discussing contracts here yet?

Mike Creel

We have been in discussions with a lot of folks. Other parts of the world, I really don’t have understanding what Mont Belvieu is, for example. So there is a lot of education going on, and frankly I don’t think you can have a spread like we have ethane to naphtha and not see some opportunity to develop. I think we said that the new facility we are building we are going to have the capability to add ethane export to it if we get the interest, and we are having lot of discussions with a lot of players.

T.J. Schultz - RBC Capital Markets

And on Aegis, what are current shipper commitments and can we discuss what you are seeing from the open season right now?

Mike Creel

I think what we have said – when we made our announcement recently, I think we said we have got quite a lot of support on that to the point that we are going to – we are building it, we are looking at upsizing it. We are talking to other petrochemicals about new plants that haven’t been announced, some of them don’t reside in the U.S. and we think more to come. So I can’t – I don’t think we want to talk about, we’ve got X number of barrels a day at this point but suffice it to say it’s going to be one heck of a project. And it’s got one long life to it.

T.J. Schultz - RBC Capital Markets

And just lastly, progress on the Seaway loop, and remind me when you expect that to be in service?

Jim Teague

We’re still expecting it to be in service probably in the second quarter of next year. Everything is going well so far.

Operator

(Operator Instructions) Your next question comes from the line of John Edwards with Credit Suisse.

John Edwards – Credit Suisse

Yeah, good morning, everybody.

Jim Teague

Good morning, John.

John Edwards – Credit Suisse

Just if I could follow-up TJ’s question on ethane export. What seems to be the bottleneck issue, I mean you’re saying you’re doing a lot of education with customers and such, maybe if you can talk a little bit about that?

Jim Teague

Hi, John, this is Jim. Yeah, you know, if we were willing. I’m just saying here – if we were willing to sell ethane relative naphtha we would be building an export. Now, if you’re sitting in Europe and your life has been naphtha then the safest thing you can do is like, hey, I will buy ethane at “X” percent of naphtha, but we’re not going to do that. So that’s the education process. You know, it’s no different, frankly, in the education process that had to be done with U.S. ethylene plants. They had to come to appreciate the state of the power of shale and what – where it’s the same story again that you have to go and you have to explain to them and educate them that hey, guys, this is for real and this isn’t going to go away anytime soon and I think you’ll get there.

Mike Creel

It might be a lot easier if there were a lot of ships already in existence to transport ethane and if there were export facilities to load those ships.

Jim Teague

And Mike makes a good point. It’s not just an export facility. They got to spend money on their end and somebody has got to build a ship. They can’t handle this stuff right now – small ethylene carriers went.

Mike Creel

Yes.

John Edwards – Credit Suisse

So, there’s also an issue with receiving the ethane, you’ll have to have some receipt terminals as well as building out transport, it sounds like.

Mike Creel

Right.

John Edwards – Credit Suisse

Okay. That’s helpful. And then if I could follow-up Daren’s question about LPG export. I mean, as far as – you know, with the amount of commitments for export. I guess when do you see it starting to impact the NGL market, particularly propane? I mean, in the U.S. is what we’re thinking.

Randy Fowler

Yeah, Mike just said it. I think it already has. We’ve seen propane prices go up. There is a lot of propane still being cracked so at a certain point it comes out of the cracker. I think there’s 400,000 barrels a day being cracked right now. 400,000, 420,000 something like that. And you know that’s a lot of supply that can come out.

John Edwards – Credit Suisse

Okay, fair enough. And then, I guess, lastly if you have any thoughts on the how you’re thinking about things with the impact now, the recent re-widening in crude spreads, how you’re thinking about your business along the Gulf Coast.

Jim Teague

Re-widening? You mean relative to Brent?

John Edwards – Credit Suisse

Yeah, Brent. Yeah, the WT – I mean, you know, narrowed substantially and now it’s widened back out to $10 or $12 and so we’re just thinking how – what thoughts you have regarding that going forward?

Jim Teague

Personally I don’t think it makes a difference. I don’t think Brent has anything to do with anything anymore. I think it’s really about LLS to WTI, and that spread last outlook was, what, 2, 22.40. So, I ask the other day, how much Brent is being imported into the Gulf Coast and I don’t – Robby, I don’t think you all came up with any, did you? Zero. So, I think it certainly puts U.S. refiners in an enviable position relative to other parts of the world. So, we quit paying attention to Brent and we’re looking at LLS to WTI and jumping through it to get crude moved.

John Edwards – Credit Suisse

Alright. Thank you very much.

Operator

And your next question comes from the line of Michael Blum with Wells Fargo.

Michael Blum – Wells Fargo Securities

Hi, good morning.

Mike Creel

Good morning, Michael.

Michael Blum – Wells Fargo Securities

I guess, a question back to ATEX and ethane rejection. And, Jim, your comments that you wouldn’t be surprised to see volumes above even the contracted levels. You know what, I guess we’ve seen mostly ethane rejection mainly in kind of the Mid-continent area. Do you think as the volumes come down from on ATEX into Mont Belvieu that, that could change the dynamics for ethane rejection in the Gulf Coast, like in the Texas market, Eagle Ford et cetera and if so, would that impact the ore volumes on either your Eagle Ford or your kind of those Western pipelines that you referenced before?

Jim Teague

Anything is possible. 70,000 barrels a day – certainly not to going to help the price, we would be foolish to say otherwise. But we have been seeing ethane inventories drop. So I think it’s a sign of a strong demand but frankly I think there is a lot being rejected and yes, I guess you could see some more of being rejected. We watch our plants – I mean every day we are looking at the economics of our plants. We are probably in a better position than anyone else to continue to recover because of our value chain and we look at our economics across the whole value chain, not just at the plant. So far we have had one plant built that has been fairly routinely in rejection other than that, everything is extracting.

Michael Blum – Wells Fargo Securities

And then maybe just in terms of your latest thoughts on industry wide what the ethane rejection number looks like?

Randy Fowler

Probably 275000 a day, somewhere in that range.

Operator

And there are no further questions at this time.

Randy Burkhalter

Okay, Molly, if you would give our participants the replay information.

Operator

Thank you for participating in today’s conference call. The call will be available for a replay beginning at 1 o’clock PM Eastern Time today through 11.59 PM Eastern Time on November 7 2013. The conference ID number for the replay is 90317221. Again the conference ID number for the replay is 90317221. The number to dial for the replay is 1-800-585-8367 or 855-859-2056. Thank you for participating in today’s conference call. You may now disconnect.

Randy Burkhalter

Thank you, and have a good day.

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