Joe Bob Perkins – President, Targa Resources Partners
Randall Fowler – Executive Vice President, Chief Financial Officer, Enterprise Products
Frank Semple – Chairman, President, Chief Executive Officer, MarkWest Energy Partners
Targa Resources Partners LP (NGLS) Company Conference Call November 17, 2011 12:15 PM ET
Thank you. The next panel topic is Infrastructure Solutions to Meet Strong Ethane Demand. On this panel, we’ve got Enterprise Products’ Randy Fowler, Executive Vice President and Chief Financial Officer; Frank Semple, Chairman, President and CEO of MarkWest Energy Partners, and Joe Bob Perkins, President of Targa Resources Partners. We’ll start with Randy.
They told us we have about four or five minutes to go through a company overview, and his message was, talk fast. Being reared in Texas and Louisiana, that’s not a talent I’ve acquired.
Just to give you a quick update, with Enterprise I think what we look at one of our strengths being is connectivity to the supply basins, whether it be the traditional supply basins or the developing shale plays and the non-conventional plays. We feel like we’ve got good connectivity there but we spend just as much time focusing on the consumers of this energy, the consumers of the NGLs, the U.S. petrochemical industry and the refining industry, so we feel like for a midstream company we’ve got good connections both to the upstream side and the downstream side.
As far as visibility to growth, I think probably some of the more noteworthy things – in the last two years, 2010 and thus far in 2011, we’ve completed about $2.9 billion worth of growth capital projects and we’ve been executing. We’ve been able to come in and largely bring those projects in on time and about 10% under budget. So we’re not seeing the cost pressures that I think we saw as a midstream industry back in that 2007 – 2008 time frame, so we’ve been able to come in and execute on these projects.
Going forward, Haynesville shale most recently we completed our Haynesville extension. That was a $1.6 billion project. We brought it in for $1.5 billion. It’s a 1.8 Bcf a day pipeline that takes natural gas from the Haynesville Bossier shale areas in north Louisiana going to the southeast. We connect with about 10 interstate pipelines, noteworthy Florida Gas and (inaudible), so we’ve been able to get producers gas into the southeast and in the Florid markets, and then also we connect with about 100 customers in the south Louisiana area, whether they be Louisiana Power and Light, whether it be some municipal utilities, or large industrial users. So again, we’re getting that producer gas instead of getting it to a hub where it needs to be transported further, we can come in and actually get them to real end-use consumers. So that project went into service last month. Incremental EBITDA, let’s call it between—over the life, probably 150 to $200 million a year, probably closer to about 160 as we start out.
In the Eagleford, we’ll—I’m not sure—yeah, that’s what I thought. In the Eagleford, we’ve got a number of projects on the natural gas side, natural gas processing, NGL liquid takeaway and crude oil takeaway. Some of our natural gas pipeline projects are extensions off our base system. Some we completed in 2010; others we’ve completed in 2011, and what that enabled us to do was to quickly be able to get some Eagleford volumes into the seven plants that we already had down in the Eagleford. We have about 300 million cubic feet a day of capacity, so we were able to quickly get that Eagleford production in those plants. We filled those plants up. In the Eagleford, we probably have about between 3.5 and $4 billion worth of projects under construction. The first phase of the crude oil pipeline ought to be in service in the first half of next year. The extension that goes deeper into the Eagleford should be completed in the second half of next year, as well as our natural gas processing plant, and then our NGL takeaway back into Mount Bellevue.
Complementary to that, we’re building a six fractionator at Mount Bellevue, another 80,000 barrel a day fractionators. We originally had on the timeline that that would probably be first quarter 2013. Our guys have built so many of these 75 to 80,000 barrel a day fractionators that they’re able to come in and bring them in on our under budget, and really the last one we brought in about five months ahead of schedule. We think probably that fractionator comes on late 2012 instead of 2013.
In total, we currently have about $4.5 billion worth of projects under construction. Not mentioned here is the proposed pipeline that we have coming out of the Marcellus, an ethane pipeline. That’d be about a 1,200 mile pipeline - 600 miles of it would be new build, 600 miles of it would be reversing an existing pipeline. We put out a press release here a few weeks ago on Chesapeake came in and took a big chunk of capacity – 75,000 barrels a day – that it would be ramping up over five years. We just completed an open season. We’re finishing the evaluations on that, and I would think we’d have an announcement on that ethane pipeline here in the next week or two.
The last pipeline to talk about, I think I heard Jeff Wood mention it earlier – we have a Texas express pipeline. It basically comes from west Texas down into the Mount Bellevue area. It’s a joint venture that we have with Enbridge and with Anadarko. We’ll be picking up, helping debottleneck that Conway area. We’ll also be able to bring additional volumes out of the Rockies, out of the Granite Wash, pick up some volumes out of the Barnett; and I think the completion date on that, I believe, is either first quarter of second quarter of 2013.
So we’re staying pretty busy at Enterprise, and I think all the midstream companies that you’ll be talking to here, very active and really we just can’t get pipe in the ground quick enough right now.
As far as—quickly on—TJ had asked to talk about ethane dynamics. This graph here on the left shows where the profit margins are for ethane, ethane being the blue line. Ethane continues to perform—outperform gas, oil and naphtha. Gas, oil and naphtha, if you would, nearly matched the ethane profit margins the ethylene industry enjoys earlier in this year when ethylene prices were so strong. Now, currently where we are is right back here where an ethylene cracker cracking ethane is probably making $0.12 a pound by cracking ethane. They are probably losing $0.12 a pound by cracking naphtha and they are losing about $0.25 a pound by cracking gas oil at this point in time.
Great success story, what the shale plays have done for the U.S. petrochemical industry as far as from an ethylene production cost. The U.S. is the third cheapest after Saudi Arabia and Iran, and they both have supply issues. They really can’t grow that ethylene capacity fed by ethane, where the U.S. we think has a lot of growth left as far as ethylene capacity additions based on ethane production growth.
And with that, we took a stab based on some data from CMAI, other announcements, and the Y-axis here is the supply side, the ethane supply side currently. If the ethylene crackers are running at about 95% of capacity, we estimate that they would consume about 970,000 barrels a day of ethane. Current extractions is probably between—well, current extractions are probably about right at 900,000 barrels a day, then you add on to that ethane that comes out of the refineries. That probably gets you up to about 930,000 barrels a day, so when the industry is running at this 970 – and actually, we’ve seen them up to consuming a million barrels a day on two occasions on August of 2011 and back in December 2010 – they’re really drawing hard on ethane supplies. The last thing I read and an advantage from an ethane supply standpoint, I think they were estimating at the beginning of December, there would be 21 days of ethane supplies in inventory. Historical has been 30 days, so again, the industry is running a little tight largely just because of the amount of ethane that’s being cracked.
The next thing we did is we tried to come in and say between 2012 and 2015, we estimate that we could see ethane supplies hit as high as 1.2 million barrels a day, but we see as far as demand response, we see probably about 230,000 barrels a day, 235,000 barrels a day of new ethane demand coming from either ethylene plant conversions, converting current capacity from heavier feedstocks to the lighter feedstocks, or coming in and doing some debottlenecking and some, if you would, step expansions. Notably, I think there was a few comments that Exxon in Baton Rouge and Shell Deer Park both went down for turnaround and took a little bit longer on their turnaround than what the industry expected. A little bit of rumor out there that maybe when they come back up, they may be able to consume more ethane than they did before they went down.
And then finally, the yellow area steps it out to 2016, 2017 as we see more volumes come on from the Eagleford, from the Marcellus. We see the supply getting up between 1.4, 1.5 million barrels a day, and once you step out into that, in order to come in and see that supply taken care of, you would really need to come in and see some of these new builds that Dow and some other companies have talked about. And what we estimate there, the new builds that have been talked about would probably consume about 250,000 barrels a day. So that’s sort of what we see from a standpoint of ethane supply-demand balance.
And with this – this is my favorite chart. This comes back in and compares Enterprise’s total return and the total return for the Alerian MLP Index going back to 1999. Noteworthy – if you come in and you look at the last three columns, Enterprise on the Alerian are number one or number two compared to high grade debt, high yield debt, S&P 500, commodities, hedge funds, international equities. We think it’s a great story just for the whole MLP universe, and just been fortunate we’ve had a lot of opportunities to come in and invest capital and drive some returns for our shareholders.
That’s your favorite slide?
My favorite, yeah!
Randy did a great job of a lead-in for my discussion. You know, TJ gave me very strict direction here that I need to talk about Marcellus ethane and the role that Marcellus is having on ethane supplies, so I’ll try to stick to that. It is hard, though, to talk about ethane without some context, and I think Randy did a good job of giving you some context about what’s going on in the broader NGL market. It’s very difficult, because the opportunities, the challenges, the value around ethane is just hugely dependent on the commercial, the operational, the economic considerations for the broader purity NGL market. So it’s hard to kind of talk about them separately, but we don’t have time to go into all that detail.
But I will say that we’ve been around since 2002, MarkWest Energy partners. We’ve spent roughly—by the end of this year, we will have spent about $4 billion in arguably some really good shale plays around the U.S., and the majority or the lion’s share of that capital has really been to support the producers’ development of the wet areas of these high performance shale plays. Every one of them are different from the standpoint of NGL value, all the operational commercial considerations, and the Marcellus is unique in terms of those same considerations. And so the next couple of slides, what I’ll try to do is just kind of talk you through what we’re doing, what MarkWest is doing up in the Marcellus, and I’ll lead you through and ultimately talk about kind of what does that mean from an ethane production supply standpoint. So I’ll try to be brief here.
This is just kind of a high-level view of our operations in the Marcellus, and kind of the takeaway from this slide is that since 2008, we’ve spent a lot of money and we’ve put a lot of infrastructure in place up there. We have currently today about 355 million cubic feet a day processing capacity at our Houston facility, which is kind of right in the middle of that slide, and we have 270 million cubic feet a day of cryogenic processing capacity at our Majorsville plant. We’re in the process of adding processing capacity at Majorsville, Mobley and Sherwood, and if you look at the information on the right, you kind of see what that amounts to.
The takeaway here is that by this time next year, we’ll have about a Bcf a day of high quality processing capacity up in the Marcellus, and that ramp-up has been extraordinary. If you just think about it, that’s occurred really over the last three years. so this kind of goes to Randy’s point about these shale plays are where it’s at. The wet areas of these shale plays is where the producers have the best economics and hence that’s where all the activity is from a drilling standpoint.
This slide basically shows you that ramp-up graphically, and you can see our projections relative to the—and this is, again, just from a MarkWest standpoint. This blue represents the ramp-up in inlet volumes, wet gas inlet volumes into our Marcellus processing facilities, and you can see in red the continued ramp-up of our current and our future processing capacity to accommodate that growth. And this occurs over the course of the next three, three and half years, and you can see that we’re basically trying to stay ahead of that curve. Now, some could argue that that’s not aggressive enough in terms of the drilling programs that are ongoing and have been announced out of the Marcellus, but it’s still a fairly significant ramp-up in volumes and processing capacity to support that growth.
And I’m getting to the ethane part here in just a second. So again, when you talk about ethane, I was talking to Will earlier today about it’s fun to talk about ethane, it’s kind of a hot topic right now, but particularly when you think about the northeast, you’ve got to understand what the implications are of the wet gas that’s being—the ramp-up in the wet gas that’s being processed and the result in NGLs. And I’ve got a slide here that basically shows propane. It’s a little bit busy, but the bottom line is you’ve got to think about with the ramp-up in Marcellus volumes from 1 Bcf, 2 Bcf to 5 Bcf, think about the resultant value that’s being created from the production of the NGLs in that stream. And so propane is a big part of that value, and so this is something we’ve been talking about with our producers for three or four years, because again it comes back from the history that we have in the other shale plays and the NGL business that we’re pretty familiar with. So you really—if you just look at propane and you think about a ramp-up similar to the one I just mentioned in terms of inlet volumes, high BTU inlet volumes, then you have on the top here on the right you’ve got the production curve for propane and the market for propane, winter versus summer. And so again, this is something that it’s not—you know, it sounds pretty easy and pretty obvious, but for a long time early in the development of the Marcellus, there was a huge amount of discussion about, well, just move that Y-grade – it’s got to be extracted – move that Y-grade down to Bellevue, fractionate it and sell it down there. Well, the point is that for C3-plus, there’s a huge market and continues to be a huge market for C3-plus, and there will continue to be a market. At some point in time, we will reach a point where exports really become a bigger part of the equation, the demand for propane—you know, there may be some petrochemical plants that are built in the northeast, but at some point in time the market essentially does not match the supply. But for the next foreseeable future, it looks like there’s a clear market, a good market in the northeast, this market in the U.S. for C3-plus.
So we get to the ethane issue. And again, as we’ve designed our system, all of our systems – and this is not just in the northeast, in the Marcellus – all of our systems really are designed to be able to optimize the extraction of ethane. And so you really have the ability to kind of turn the knob and determine what kind of—you know, how much ethane you’re going to extract in the stream, if it is economical to extract that ethane. So in the case of a Marcellus, we were designing our systems, and have from the very beginning, to be able to maximize and optimize the extraction of ethane, and this slide basically shows on a must-recover basis and a total recovery basis, dark blue versus light blue, the ramp-up in ethane production in the northeast. The red represents, again, the design of our system to be able to extract, to be able to fractionate and produce that purity ethane.
So takeaway – we’re staying ahead of the curve. It’s a steep curve, and currently we’re blending the ethane. There are waivers for a number of the producers in the downstream pipeline that’s allowing us to continue to blend that heavy BTU—that 1120 plus into the downstream pipelines, but it generally goes away in late 2013, early ’14. That’s about the same time that Mariner West and our de-ethanization facilities at Majorsville and Houston come onstream. That’s that big jump in de-ethanization capacity, again for our Liberty facilities up in the Marcellus.
This happens to be Wells Fargo – sorry, TJ – but this happens to be Wells Fargo’s graph. Just to give you kind of a third party perspective, not just MarkWest’s perspective about the ramp-up and the total ethane that’s in the stream in the Marcellus. You can see the numbers are a little bit differently, but the point is still the same, that there seems to be with MarkWest as well as the other announced projects, not plenty but adequate capacity, de-ethanization capacity to be able to support the ramp-up in the wet gas in the Marcellus, so that’s good news. So again, it’s fairly consistent with the slide before.
My last slide is really on what we call our Mariner projects. For those of you that aren’t familiar with that, we’ve been working with our producers for the last two to three years, because we’ve kind of seen this ethane issue coming on, developing several projects that would be able to help the producer maximize the value of their ethane. We have a Mariner West project and a Mariner East project. The Mariner West project essentially transports the purity ethane out of our Houston facility up to Sarnia. It’s about a 50,000 barrel a day project. Sunoco Logistics is really the operator. They are really running this project. All we’re doing is we’re providing the ethane through our facilities, and we’re building a small interconnect to supply the Sunoco Logistics system with the purity ethane. So Sunoco went through the buying open season a couple months ago. They have adequate, firm commitments to that project moving forward. We’re moving forward with the construction. It will be online middle of 2013 to support the ramp-up in ethane production that I mentioned earlier.
The second project – again, very similar – we’re doing the Mariner East project with Sunoco. Sunoco will be the operator. We essentially provide the purity ethane through an interconnect to their pipeline facilities to transport the ethane over to Philadelphia, where it will be put on barges. It will be sold internationally or it could be transported down to the Gulf Coast. Sunoco hasn’t conducted the open season for that yet, but got a lot of interest there. The Enterprise project that Randy mentioned is, I think, a great option—addition for ethane capacity out of the Marcellus. We will need certainly all of these projects if you believe the ramp-up and the demand that Randy mentioned earlier so we’re moving forward with Mariner East. Still a lot of interest in developing that kind of optionality for the producer customers, and we think it will be a nice complement to the overall ethane market out of the Marcellus.
Thanks a lot. Joe Bob?
Joe Bob Perkins
Frank talks pretty fast. I thought Randy did pretty good from Texas and Louisiana, but someone named Joe Bob can’t compete with either one of those. Speaking of competing, I sat on a panel just a few years ago with Enterprise, and I have to say we’re not even one-tenth as large as Enterprise, and we’re catching up, which is a good thing. Maybe if you’re thinking about growth, starting from that small base is also a good thing.
I’m going to try to show you were Targa fits in the natural gas liquids story that we’re telling you today, add a few perspectives on what’s a pretty complete picture already said, and then we’ll open it for questions.
If you start with how we fit, we’ve got two businesses – a gather and processing business, and then a natural gas, liquids, logistics and marketing business. This part of the business – the gathering and processing side – is about 60% of our operating income. We’ve got field gathering and processing that’s pictured, a leading presence in west Texas and the Permian. I’d say overall we’re probably the leading Permian gatherer and processor. In north Texas, we’ve got a very strong position, particularly in the oilier part of the Barnett shale, and you can see our system there. Coastal gathering and processing segment – not quite as sexy right now, but a very good business on southwestern Louisiana own shore and strewn across the Louisiana coast. A great catcher’s mitt for the Gulf of Mexico as regulators get the heel of their boot off of producers’ throats. We look forward to that returning as well. It’s a great gathering and processing business.
Our logistics, marketing and distribution business, we always show sort of dots coast to coast but those are propane and refinery services marketing and terminalling facilities for the most part. Where the core of our natural gas liquids assets resides is Mount Bellevue, Galina Park, and all the way to Lake Charles, Louisiana. That’s an impressive set of assets – very hard to replicate. We think it’s a leadership position.
In terms of fractionation, we’re number two behind someone else on the panel here. On Lake Charles and Mount Bellevue fractionation, we’ve been adding to that as well, not quite as fast as my friends but still trying to meet people’s needs for additional fractionation in this important market.
This is our picture of the industry dynamics that are going on related to natural gas liquids and how Targa is participating. We used to try to talk about how we were going to participate in the Marcellus shale and get into that resource play, and that wasn’t very long ago. We weren’t successful, a sort of second-ran a couple times, maybe competing with someone else on this panel. We didn’t get to that resource play but the resource plays came to us, and that’s very fortunate. The same seismic geophysical interpretation, drilling technology and completion technology that drove those plays are driving plays on this map. The same thing is going on. It’s resource plays now around our footprint, and that’s pretty attractive. Let me just touch on some of them.
If you look at Versado in the Permian business, primarily Sand Hill which is not labeled, sits between Bone Springs and Wolfberry there. If you follow the E&P side, you know how active that is. It’s resource plays increasing production for the E&P companies, increasing processing for the gathering and processing companies. Move over to the east – St. Angelo – setting records over the last several years of well connects there, resource plays in the Wolfberry very active. We’re growing that. We’ve added capacity at St. Angelo. Go to the Barnett shale in north Texas, our position was kind of sleepy there for a while. When we first acquired it, there was a lot of activity in the dry gas portion. We weren’t that well positioned for the dry gas portion, but we’re very well positioned for the oily part of the Barnett. We’re increasing processing through there. We just announced a new 200 million a day processing plant in north Texas benefiting from that older resource play in the Barnett shale.
The same dynamics impacting the Eagleford, the Granite Wash, plays in the mid-continent and Rockies. Lots and lots of liquids driven by producers drilling oil wells and very high liquid content gas wells. That’s not going to stop. It’s happening in a $3.50 gas world. It’s driven by the condensate, driven by the oil, driven by the natural gas liquids, and all of those liquids have to come into Mount Bellevue, and we’re trying to help. Trying to help with the fractionation, help with the terminalling, and eventually – because there is that much ethane being produced, there is that much propane being produced – this country isn’t growing in propane demand. Some of it will be used in petrochemicals, and you’re seeing new announcements for the propane; but if it weren’t for Enterprise and Targa right now, we’d be in a propane oversupply position. Enterprise has done a lot exporting international-grade propane. We’ve done a lot exporting domestic-grade – HD5 propane. To help the propane situation, we recently announced a project there as well to increase our ability to export propane from Galina Park, this time international grade.
So those dynamics are a heck of a story. It is in fact a new game. It’s game changer, all driven by shale play technology, and E&P companies’ desire to drill for oil or drill for high liquids. From an industry standpoint, we’ve responded. If you took that 680,000 barrel a day fractionation capacity shown in 2009 – the blue bar – I could go back 10, 20 years and it’s about the same. By 2013, we will have doubled to about 1,300,000 barrels a day with other projects probably required after that. If you look at the pipeline capacity that’s being added in red, you can see more pipeline capacity announced and online than fractionation capacity, which is why we announced – Enterprise, I’m sure – are studying what’s the next one. It’s going to be necessary to meet the E&P companies’ requirements. I’ll show you some projects in a minute. But our fractionation projects, we’re contracting for 10 years with very high frac-or-pay requirements and therefore adding to a great deal of EBITDA growth in the future.
This is a repeat of what other folks have said – top right shows were the pet-chem capacity is in the United States and Canada. Eighty percent of it is along the U.S. Gulf Coast. That’s the best place to add additional pet-chem capacity then. It’s all interconnected. The bottom left shows an increasingly light feedstock for the pet-chems, using more ethane, using more propane instead of naphtha. The bottom right is a different version of the chart I think Randy showed where it’s only the Middle East that has a cost advantage relative to the U.S. Gulf Coast. It has supply issues Randy didn’t mention, but he would have if he wasn’t trying to talk so fast. The U.S. is about that much more stable than the Middle East right now. If I’m a pet-chem, this is where I would be spending the dollars.
This is a chart we’ve been trying to explain. Our many growth projects for a little company, that’s an awful lot of growth projects. We’re proud of them. We’ve been working on them very hard. They come in on time, on budget. If you look at the top group there, 2011 – 2012, there are four projects that are liquids-related, the liquid story we’re talking about at this session. First, CBF Train 3 – that was our first expansion. We only had to build about half a fractionator there. We got it on very fast and very cheap and added 78,000 barrels a day of capacity. It’s already online. It will be online completely full quarter for Q4. If you go down a little bit, you see the benzene treating facility and the HD5 export enhancement that we made, backed by term contracts, and an expansion at the Gulf Coast fractionator where we are a partner in the particular fractionator.
Our 2013 projects – CBF Train 4 will be coming on in the first quarter of 2013. That’s an additional 100 million a day of fractionation – again, fully committed, high percent take-or-pay. And you go down a few more lines, you will see our announced international propane export project, and that was a very high need for propane to be exported from our Gulf Coast terminal. By the way, that’s the only terminal in the Gulf Coast that can export ethylene as well. We just keep adding capabilities there. That international propane export coming up in mid-2013 is made even more attractive by the expansion of the Panama Canal and the ability to take very large gas carrier ships through the Panama Canal.
That’s sort of our growth picture. We’re very proud of it, and I’m all that’s standing between you all and questions.
Question and Answer Session
Great. I appreciate it. Obviously a very thorough view from these guys. I think we got a good picture on different parts of the play. I don’t know if there’s any specific questions. Sorry, here?
The ease of building your pipelines in the Marcellus (inaudible).
So are you talking about the pipeline potentially—
Yeah, just let me repeat. The question really is just kind of ease of—kind of the process for building the pipeline from the Marcellus, and then specifically if you have thoughts on New York.
Okay. Our pipeline won’t go to the eastern side of Pennsylvania. It’s more on the western side of Pennsylvania and then through Ohio and then down. We’ll be following, if you would, sort of the TEPCO right-of-way – the Texas Eastern Products pipeline right-of-way. What we found from the discussions that we’ve had with regulator and government types in Ohio, they were looking forward to having the jobs, and so I think they’ve been constructive there. As far as coming in and New York not allowing drilling, I mean, from my standpoint I think the other states can pretty well handle it as far as from a resource play standpoint.
So Frank, I don’t know if you have any thoughts on that from a Marcellus standpoint?
Well, the more options, the better. It’s unfortunate that New York has not opened up for drilling. The producers—there’s a lot of acreage up there, prospective acreage up there to drill. That being said, I agree with Randy. I mean, it’s helped the Pennsylvania, West Virginia ultimately with the Ohio acreage being more productive, and there’s plenty of acreage there to develop the kind of volumes that we’ve been talking about here. So New York, it’s going to be tough for them to catch up, particularly gas price—it’s mostly dry gas up in New York, so it’s really difficult to make the economics work or be able to compete with the richer gas areas that we’ve been talking about down in the Marcellus and Utica.
Yeah, question is Europe (inaudible). What kind of slowdown do you see in petro-chem export business down to Europe and what does that do to your export market, either propane or anything else, (inaudible).
So just to repeat for the webcast – the question is just given some of the uncertainty in Europe, what does that to really to your expectations for the export market?
Joe Bob Perkins
I’ll take a crack at that one. As a world economist, there are a lot of people better than me. The bigger demand and the growth in demand for petrochemicals is Asia rather than Europe. If your contagion takes the whole world down, every industry I know about is going to be in trouble. But other than that, global demand, demand in China, demand in India driving reasonable growth in petro-chem needs against an advantaged petro-chem market in the Gulf Coast relative to naphtha-based pet-chems in Europe, I believe you will see them continue to invest and operate at high utilization rates.
Isn’t it also a market share issue? I mean, even if the overall market is a little bit less, the question is how competitive is the U.S. market for that production; and again, the margins will be driven by that market overall. But I think the U.S. is positioned pretty well to compete for that market, no matter what the size.
And I think currently you’re seeing with the—crackers in Europe are coming in and trying to maximize their utilization of propane, dialing down the amount of naphtha that they’re using, just because again the same profit dynamic over there. And I think one of the things that’s happening currently in Asia, their diesel supplies are so tight that they are—the refinery, they are minimizing the amount of naphtha that they produce to try to maximize the amount of diesel they produce because they’re in such a tight situation, and as a result their ethylene crackers, I think, are running like 85% of capacity just because of the naphtha. It’s not available to crack the naphtha.
Maybe if we can – Randy and Joe Bob – kind of focus on Mount Bellevue for a second, and then Frank, maybe I’ll touch on the Marcellus. But when we look at – I think Joe Bob has the last slide up – we saw some of the pipeline capacity coming into Bellevue and some of the fractionation capacity, just your thoughts on what is the opportunity to expand fractionation capacity above and beyond what has already been announced out there as you look out over the next, call it three or four years.
Joe Bob Perkins
You’ve got announced projects that are under construction. We said we were studying our Train 5. I believe that several more fractionators will be build beyond what’s announced. Our Train 5, Randy can speak for himself, Energy Transfer probably will build another one as well, and they will be full.
Yeah, I echo Joe Bob. We’re evaluating everything. Everything we’ve built thus far—so frac 5 just came up, frac 6 is, call it a year and a couple of months away, and they are already sold out, long-term contracts. And we’re evaluating expansions as well, and the only thing we’re predicating the volumes on are the volumes that are coming in on pipelines that we own 100% of or we’re a joint venture partner on. We’re not looking to come in and, at this point, we’re not building fractionators based on volumes coming in from third party pipelines. It’s just pipelines that we’ve really got the visibility on, and as Joe Bob said, you come in and elect to do another fractionator, it will be sold out too. One of the safety valves that we’ve got is we probably have the capability to swing, call it 70,000 barrels a day of NGLs over to our fractionators in Louisiana that sort of, if you would, is our overflow. So when we come in and turn on frac 6, all we’re doing is we’re not going to send barrels to Louisiana. We just fill up frac 6 immediately.
Joe Bob Perkins
Interesting point – we, to a lesser extent, do the same thing to our Lake Charles fractionator and our (inaudible) fractionator in Louisiana, but we’re seeing liquids already beginning to increase in Louisiana from the Chalk and the Wilcox. Our wellhead production in southwest Louisiana, to the LOU facility has doubled over the last years. So there’s not a shortage of liquids, and Louisiana will probably be getting its own versus us swinging it back and forth there pretty soon.
Frank, maybe last thing here. Certainly we’ve talked a bit about the Marcellus. Maybe you can touch on the Utica and some of the opportunities that you think that may present. I mean, obviously we’re still early days, but the potential you see there and kind of how it may impact your plans over the next few years.
Well, it’s an exciting play. I mean, the public information coming out of the producers represent not only a significant resource play but also the performance of those initial wells are pretty spectacular. So to kind of put it simplistically, I think it’s another potential Marcellus in terms of the production of liquids that could be extracted from that gas stream. So it is early, no doubt about it; but the fact that there’s a significant amount of infrastructure in the Marcellus that has been built, you’ve got companies like Enterprise, again, investing in takeaway projects for ethane, I think bodes well for the Utica producers because they can just basically take advantage of some of that infrastructure. Now, most of the discussion with the producers has been around keeping as much of those facilities and those assets in Ohio, and I think that’s a smart move for a lot of reasons. But the fact that the Marcellus has really driven the development of a lot of this midstream infrastructure, NGL-focused midstream infrastructure, will be a good thing for the Utica producers. More options – that’s a good thing.
Anything else? I think it’s a very good job for each of you guys in your presentations, and I appreciate it. I think we’re out of time for this panel. Thank you very much.