Enterprise Products Partners LP (EPD) 2013 Q3 法說會逐字稿

Good morning. My name is Molly. 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. (Operator Instructions). Thank you. I would like to turn the call over to Randy Burkhalter, Vice President of Investor Relations. You may begin your conference.

Thank you, Molly. Good morning everyone, and welcome to the Enterprise Products Partners conference call to discuss the results of 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 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 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 will turn the call over to Mike.

Thank you, 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 pipelines, 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 both quarters in 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 of 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 distributable cash flow for the quarter and over $900 million for the first nine months of this year. Retained distributable cash flow is available to reinvest in the growth of the partnership and reduce our reliance on the capital markets.

Approximately $250 million of year-to-date retained distributable cash flow are from proceeds of the sale of non-core assets that were earning a relatively low return on capital. We intend to re-invest these proceeds in projects with higher returns on capital and further increase EBITDA and distributable cash flow.

The NGL Pipeline and 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 Mountain 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 from fee-based processing activities.

Fee-based natural 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 of 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 the 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 of 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 pipeline and 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 benefited from increased production from the Eagle Ford Shale.

Our onshore Crude Oil Pipelines and Services segment reported gross operating margins 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 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 the Eagle Ford joint venture pipeline with Plains, primarily due to a combined 234,000 barrel a day increase in volume. Partially offsetting increases in gross operating margin was $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 Products 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 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 a 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 will 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 5 to 15 year contracts.

While some of the projects will have a volume ramp up period, such as the ATEX and the Aegis projects others 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 have seen our gross operating margin grow 45% from $3.25 billion in 2010 to $4.7 billion for the trailing 12 months ended 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 sizable 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 in ensuring the successful execution of these projects, completing them, and with very few exceptions, they are brought in on time and on or under budget.

Before I turn the call over to Jim, I would like to close by saying that we are very pleased with the solid results generated by our businesses 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. With that, I will turn the call over to Jim.

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 should say margin pressure. And that is 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 is anything but business as usual.

Explosive growth of US shale hydrocarbons is now changing not only the US, but the global landscape, and we are 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 have 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 filled 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 our Yoakum plant and, at over 140,000 barrels a day, it may be the largest NGL producing plant in North America. In addition, in keeping with our link-and-leverage approach, all of these Eagle Ford assets feed other Enterprise assets in Mont Belvieu, and they are available to support a growing list of projects for new demand, some outside of the US. 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 have been quoted saying, we are not going to build any more fractionators, but given the list of customers that continue to call, the folks that run our fractionation business have convinced us to seek permits for two additional fractionators, and that is not an announcement that says that we are building them. It is just saying that we can.

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

Starting the extensive pipeline build-out we have under construction to build-out what we have referred to as Western pipelines, that is Texas Express, Front Range and our Mid-America Rocky Mountain expansion is progressing. This morning, we announced that we have begun service on the 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 are quite proud to be aligned with. At Texas Express our partners are Anadarko, Enbridge and DCP. In Front Range our partners are Anadarko and DCP.

We are constructing these pipes and will operate both of the joint venture pipelines, and every one of these projects are backed by firm demand, 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 would not be surprised to see our flows exceed the contracted volumes as producers look for ways to get their wells flowing. We will begin line-filling this project in December.

And the last regulated project I will address is our Aegis ethane header. This is another project that 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, we will be providing reliable supplies of ethane to Petrochemical facilities through a header that literally that 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. 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 insures the reliability and efficiency needed to encourage new markets for growing shale hydrocarbons, and I have to give credit to Lynn Bourdon whose idea building an ethane header he had three years ago.

Regarding crude oil, the Seaway looping is progressing and will be up mid next year. The Jones Creek extension goes from Freeport up to ECHO the first part of January, and the lateral to Beaumont/Port Arthur mid 2014. And 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 out 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 will have access to this slate of crude and direct refiners that we will 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 will play a key role in moving varying types of crude to the entire Gulf Coast.

We are going to marry growing supplies from Canada, the 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.

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 LPG's for export from the US, 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 realized 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 developed. We have re-purposed assets as flow patterns changed, 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 but not least, export capabilities for LPGs, refined products and crude oil. Adding 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.

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 in 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 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 assets 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 principle balance. Our weighted average cost of debt decreased to 5.3% for the third quarter 2013 compared to 5.7% for the third quarter of 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. Included in the provision for taxes this quarter was the $7 million adjustment to the Texas margin tax expense accrual related to the legislation 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 pipeline 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 30th was 13.4 years using the first call date for the hybrids. Our effective average interest cost of debt at that time again was 5.2%.

During the third quarter, we received $299 million through our ATM, dividend reinvestment plan, and employee purchase program plans 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 and our retained DCF continue to provide us flexibility on our timing and size of offerings when we come to the capital markets. Privately-held EPCO 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 7th.

This will bring their 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 are ready for questions.

Okay, Molly, we are ready to begin our Q and A.

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

Good morning.

Good morning, Brian.

Can you provide some color on the new LPG export terminal perhaps a range of cost/location options?

I do not think we ever said what it cost, and we have not decided where we are going to put it.

Jim, can you give us some options? Do you have a couple of options available where you might put it, and obviously access to Belvieu is important. Anything you can provide would be helpful.

It will be on the Gulf Coast. We have pipeline capacity that will be able to access it. We should be able- -where is Randy? Probably in the next couple of weeks, we are going to be able to say where that is going to be built.

Okay.

I am a lot of help, right?

Well, we will stay tuned. 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.

Yes, Brian, this is Randy. I think we are in that same range.

Okay, just maybe in 2015 that number will be higher than initially thought? I guess anything on maintenance CapEx in terms of what you are looking at for next year.

Brian, we are going through our planning process now, but again, I think we are probably going to be probably in the similar range of what we were for this year 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 will be able to give a better update at that point in time.

Okay, and then could you, what is your view on the, for Seaway, the ALJ ruling on the tariffs, and what would be in terms of a negative outcome scenario, what type of impact do you think that could have?

This is Bill Ordemann. I do not think we expect a negative outcome on that. We had gone through this process late last year, the FERC staff, and the hearing had challenged these committed rates, and we put a petition to declaratory order into the FERC to get them to essentially uphold their longstanding policy that they honor those committed rates that were entered into during open season. We are pleased with the response that we got back from the FERC at the time. They basically said they uphold those rates.

During the hearing and on the ALJ's initial decision that really is a recommendation of FERC, surprisingly enough, I guess to us, she did again challenge the committed rates. So we have filed 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 honored those committed rates. The final paperwork will be in by the 5th. We will see how long it takes the FERC to rule on that. We have already heard from them once a positive ruling, and we do not expect otherwise.

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

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

Well, you keep spending money, and it keeps bringing in cash flow.

I know. It is a high class problem. As we have said before, we continue to look at what our projects are in our backlog, and we are 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 unitholders. We look at that every quarter and try to assess what our internal needs are and what the appropriate distribution rate is.

Thanks, Mike.

You bet.

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

Jim, I got a couple questions for you. 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 is outpacing take away capacity, but more importantly, how you see that evolving over the next year, and what you think that does to price? Where I am going with this is I am 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?

That is the longest question I have ever gotten, Darren.

It is about five pounds of information in a ten pound bag. The other way around actually.

Let me see if I can remember. We are going to start line filling ATEX in December. So we should have that in service sometime in January. We figure by the end of January we will be delivering into Mont Belvieu.

We are going to start out, I think, we start out at about 70,000 barrels a day in that neighborhood. I do not know if we will see more or not, but what I said was it is not going to surprise me as these guys are having some issues up there.

In regard to the two Y grade pipelines, that is why I said we filed 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 does not help it at all.

Yes, okay. And then last question, just switching gears to your comments around the LPG export facility, and I recognize that you have got contracted commitments for that capacity, but when you start thinking about what you are adding as well as what competitors are adding both announced and proposed, when do you think we get to a point where the US 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 arb spread more so than it has and it really starts to impact propane pricing.

Well, I worry about everything. We call it an LPG export facility for a reason. I do believe that LPG will be exported from the US, but I do believe that you are going to see a lot more butane exports in the future than we have seen in the past. Yes. There is a point that you are going to be exporting butane rather than propane. But what I look at, is I look at it in the context of the total rather than product-specific.

Okay, thank you Jim.

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

I have several questions. Good morning. Just to tag on to Darren's question. 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 you think is the upper limit of demand to absorb growing US exports of propane, butane, and possibly ethane. 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?

Let us talk first, as long as there are a lot of crackers in other parts of the world using naphtha, and LPG can be exported from the US at a price that can displace that, the demand is beyond what we would traditionally think it would be. Lynn, is that right?

That is correct.

Okay. Your other question, fractionation, I did not say we were going to build it. I said we can if we choose to. But I always worry about fractionation capacity. I was here when we were doing deals at a penny and a quarter. Yes, we worry about it, and we are going to manage it. One of the things that we do, hang on just a second. One of the things we do not just - we are like an airline at Mont Belvieu.

We overbook, and we use our fractionation capacity throughout our system. When we manage our fractionation business we are not managing Mont Belvieu. We can get our Y-grade to almost every fractionator we have got and switch it between. What we are looking at is we are running Hobbs, Shoop, Mont Belvieu and our fractionation in Louisiana. We run it as one big complex, and that is how we manage it.

So, what I am thinking, we are not going to be building fractionation to support export demand. That is kind of what I was getting at, is export demand claims a greater portion of the purity products. How does that impact? 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 fractionation? That is kind of where I was going with that.

I would start out by saying expert demand is real. I do not think it is specific to just LPG. We are building an expert facility on refined products because we believe this market is evolving into a large export market. In term - I guess I look at demand as demand.

Now 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 my hat on just exports. That is why we build ours on the Gulf Coast in combination with our ability to distribute domestically. Exports you are going to have times when exports slow down. It is 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.

I see, and then just last question, and I will get back in the queue. It seems to us that the E&P industry is moving from a point where multiple speculative shale plays are 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 recurrence. Given the narrowed-breath of the unconventional resource narrative, how does this impact both the competitive and investment landscape going forward for midstream operators?

I guess I will take that one if that is all right. This is Tony Chovanec. It is true that new envoy kind of shale plays has slowed down. But it is also true that we are continuing to get more and more of the shale plays that we have and be much more efficient both from a cost standpoint and what we are getting per well. If your concern is that the shales are going to peter out, if you will, that is not what we believe at all. As a matter of fact- -

It does play to your strength for those that are already in those big plays. It might have some implication for consolidation down the road.

You mean relative to the E&P players?

To the midstream operators.

Mark, you are seeing more MLPs being formed, but as always it is difficult to do MLP combinations.

Right.

Particularly when more and more of these have publicly traded GPs, and frankly as far as we are concerned, we have better places to put our money.

Mm-hmm. Okay, great. Listen, I appreciate that. Thank you.

Your next question comes from the line of TJ Schultz with RBC Capital.

Good morning. Sorry, one follow up on LPG marine terminal. You have the flexibility to add ethane export services as that market develops. If you could expand on the interest you are seeing in ethane exports, or are you at the point of discussing contracts here yet?

We are having discussions with a lot of folks. Other parts of the world they really do not have an understanding of what Mont Belvieu is, for example. So there is a lot of education going on.

Likely, I do not think you can have a spread like we have ethane to naphtha and not see some opportunity develop. 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 a lot of discussions with a lot of players.

Okay, thanks. On Aegis, what are current shipper commitments, and can you discuss what you are seeing from the open season right now.

I think what we have said and we made our announcement recently, 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 looking at other Petrochemicals about new plants that have not been announced. Some of them do not reside in the US, and we think more to come. So you know, I cannot, I do not think we want to talk about we have got X number of barrels a day at this point, but suffice it to say that this is going to be one heck of a project, and it has one long life to it.

Thank you. Just lastly, progress on the Seaway loop, and remind me when you expect that to be in service.

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

Okay, thank you, guys.

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

Yes, good morning, everybody.

Good morning, John.

If I could follow up TJ's question on ethane export. What seems to be the bottleneck issue? You say you are doing a lot of education with customers and such. Maybe if you could talk a little bit about that.

Hello, John, this is Jim. If we were willing,I will just say it, hell. If we were willing to sell ethane relative to naphtha, we would be building an export dock. If you are sitting in Europe, and your life has been naphtha, the safest thing you can do is to say I will buy ethane at X% of naphtha. We are not going to do that.

That is the education process. It is no different frankly than the education process that had to be done with US ethylene plants. They had to come to appreciate the staying power of the shale. It is the same story again. You have to go and you have to explain to them, and educate them, and hey, guys, this is for real, and this is not going away any time soon. I think you will get there.

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.

Yes. Mike makes a good point. It is not just export facility. They have to spend money on their end and somebody has to build a ship. The only thing that can handle these things right now are small ethylene carriers, Lynn?

Yes.

So there is also an issue with receiving the ethane? You have to have some receipt terminals as well as building out transport, it sounds like.

Right.

Okay, that is helpful. Now if I could follow up, Darren's question about LPG export. 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?

Yes, Mike just said it. I think it already has. We have 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 are 400,000 barrels a day being cracked right now, Lynn?

400-420 something like that.

That is a lot of supply that can come out.

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

Re-widening, you mean relative to Brent?

Yes, Brent. The WTI narrowed substantially, and now it has widened back out to $10 or $12. So we were just thinking, what thoughts you have regarding that going forward?

Personally, I do not think it makes a difference. I do not think Brent has anything to do with anything anymore. It is really about LLS to WTI. That spread last I looked was 220-240?

Yes.

So I asked the other day how much Brent is being exported into the Gulf Coast, and I do not - - Robbie, I don't think y'all came up with any, did you?

Zero.

So it certainly puts US refiners in an enviable position relative to other parts of the world. We quit paying attention to Brent, and we are looking at LLS and WTI and jumping through it to get crude moved.

All right. Thank you very much.

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

Hello. Good morning.

Good morning, Mike.

The question back to ATEX, and ethane rejection, and Jim your comments that you would not be surprised to see volumes above even the contracted levels. We have seen mostly ethane rejection in the mid-continent area. Do you think as the volumes come down on ATEX into Mont Belvieu that could change the dynamics for ethane rejection in the Gulf Coast like in the Texas market, Eagle Ford, etc., and if so, would that impact your volumes on either your Eagle Ford or your western pipelines that you referenced before?

I guess anything is possible. 70,000 barrels a day is not going, certainly not going help the price. We would be foolish to say otherwise. But we have been seeing ethane inventories draw.

It is a sign of strong demand, but frankly there is a lot being rejected, and yes, I guess you could see more 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 one plant build that has been fairly routinely in rejection, other than that, everything is extracting.

Okay, and then your latest thoughts on industry-wide, what ethane rejection number looks like?

Tony?

Probably 275,000 a day. Somewhere in that range.

Okay, great. Thank you very much, guys.

There are no further questions at this time.

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

Thank you. One moment, please. Thank you for participating in today's conference call. The call will be available for replay beginning at 1 PM Eastern time today through 11.59 PM eastern time on November 7, 2013. The conference I.D. number for the replay is 90317221. Again the conference I.D. 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. Thank you, and have a good day.