Executives
Al Swanson - Chief Financial Officer of Plains All American GP LLC and Executive Vice President of Plains All American GP LLC
Michael N. Mears - Chairman of Magellan GP LLC, Chief Executive Officer of Magellan GP LLC, President of Magellan GP LLC and Chief Operating Officer of Magellan Gp LLC
Eric Slifka - Chief Executive Officer of Global GP LLC, President of Global GP LLC and Director of Global GP LLC
Analysts
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Magellan Midstream Partners, L.P. (MMP) Bank of America Merrill Lynch Refining Conference March 7, 2013 12:15 PM ET
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Welcome to the Infrastructure portion here of today's Refining Conference. We're pleased to have with us 3 significant players on the midstream side of Infrastructure, put you on the crude oil and refined products side of things. With us today, we have representatives from Global Partners LP, ticker GLP; Magellan Midstream Partners, ticker MMP; and Plains All American, ticker PAA. So from Plains we have Al Swanson, CFO of PAA. At Magellan, we have Mike Mears, President and CEO. And finally, of Global, we have Eric Slifka, President and CEO as well.
So I think the format of this presentation before lunch will basically be each of our 3 representatives go up and talk for about 5 minutes about their MLPs and their involvement in the midstream space. And then I think we'll have a panel discussion here. We'll ask some questions, and we certainly are welcoming audience participation in terms of that Q&A session.
So with that, I think we're going to go in reverse order, and we're going to start out with Al. So, Al, just take it away.
Al Swanson
Thank you, Gabe. I'm going to spend just 5 minutes, just briefly giving you an overview of PAA and also some of the fundamentals of how we think we're very uniquely positioned for the industry and the development of the oil shales in North America.
First, if I just can provide a little bit of a financial and operational overview. We're kind of a top 5 sized MLP, enterprise value roughly $25 billion, 4.1% yield, rated mid-BBB by both agencies.
On the right-hand panel, you see kind of our asset overview. 18,000 miles of pipeline, principally all crude oil. Significant liquid storage. Again, principally crude oil. Some refined products as well as NGL storage. We have a natural gas processing and fractionation of NGLs, as well as a very significant, what I call logistics assets, which include a significant amount of railcars, which is a very topical thing today. As well as a significant amount of trucks, trailers and barges.
We handle a little over 3.5 million barrels a day of physical product. We also provide very public guidance. Each quarter we file an 8-K with detailed guidance. The guidance for 2013 midpoint, a little over $2 billion of adjusted EBITDA and a little over $1.2 billion of adjusted net income.
We really operate and handle 4 of what we call product slates. Crude oil is by far the biggest. Roughly probably 80% of our cash flow comes from the crude oil activities. What the picture kind of shows is what we do and what we don't do. We don't own production. We don't own the refining. Both the producers and the refiners are our customers. And we basically handle the product in between. So we'll move product for third parties on our pipelines for a tariff. We'll lease terminal storage to refiners that need storage. But we also -- part of our business is we'll buy and sell crude oil. We buy it from the producer and move it to market and resell it. We take title to it, but we don't take flat price risk. Basically the purchase and the sale are matching and offset. We have a similar midstream kind of focus with the other product slates that we handle: natural gas, liquids, refined products and a natural gas storage as well.
The next couple of slides I'm going to touch -- clearly, what we're seeing in North America is very significant production growth. If you look at the U.S. and Canada combined, we're number 3 and number 6 in the world for oil production. You combine them, they're number 3, basically, the equivalent of Saudi in Russia. 1.8 million barrels a day of growth over the last kind of 2.5 years. In essence, that equals the rest of the 7 -- or 8 largest oil producers in the world. We are leading the world in oil production growth. That growth is accelerating, which is depicted on the bottom chart. We're seeing it actually increase at a much more rapid rate today than we have over the last several years.
We expect that to actually continue. What this chart shows is the fact that 1.8 million barrels a day of increased production in North America. We view this as kind of Plains' forecast in incremental 3 million plus barrels over the next several years of increased production. In the areas that you see, Canada, Eagle Ford, Permian, Bakken, Mid-Continent and the Rockies, we think we have a very unique position in all of those areas. Strong asset position and business position as well.
The other thing that we see is coming is a lot of light sweet products. In essence, in what we expect to see is, to date we've seen a lot of locational differentials. We think we'll start seeing a lot more quality differentials as we look forward, again, creating logistical challenges for the industry.
This map really takes those areas. You see the production -- areas of production growth. Canada, Bakken over 50%, overlaid against where our assets are. Again, we think we're well positioned in all 6 of these areas that we expect significant growth. Where have we been putting our investment dollars over the last several years and including this year? We'll have invested over $5 billion of growth capital in these areas. That capital will drive growth as we look ahead over 2013, '14 and '15. We think we're very well positioned.
One of the investments we've been making of late is add to our rail capacity. We view rail as a longer-term solution than most people expect to move products from the significant supply areas to the markets that really need it. We made significant investments in 2012 and have active construction projects going on now. We see rail as a very significant part of what is going to be needed as we look out over the next decade in North America.
To summarize just kind of my last slide, we think business profile, assets, positioning have driven good substantial growth. 30% compound on EBITDA, 7.7% on our distribution growth, good solid returns, 20-plus percent returns if you look at a 5 or 10 year basis. Well ahead of the peer group, well ahead of the broader indices. With that said, we think we're as well positioned or better position today and the fundamentals are stronger than at any point in that 10-year period as we look back.
And with that, I guess, we'll let Mike go next.
Michael N. Mears
Good afternoon. I'm going to quickly try to go through the base business, describe the base business of Magellan and then talk about the growth projects that's really kind of changing the direction and strategic focus of the company going forward.
To start with, I want to talk about our corporate structure. We've got a very simplified corporate structure. We are structured as a mass to limited partnership. but we have no general partner that has an economic interest in the business. So we have no IDR. So the benefits of that, first and foremostly, is all of the cash flow flows directly to the LP unit holders, and we have no conflicts of interest that might arise with a general partner with regards to building the cash flow for the LP units. So we've got a very clean corporate structure. It also leads to one of the lowest cost-of-capital in the industry.
Our existing business is primarily refined products. This is an asset map for existing business. The green line is really the core of our system. It's about 75% of operating income right now, which is our refined products pipeline system. We are, as you can see, very strong in the Mid-Continent portion of the country. We're connected to over 40% of the refining capacity in the country. We have very strong terminal positions in the Upper Midwest. We're connected to all the refineries in the Mid-Continent. Some of those refineries, we're their own pipeline outlet. We have a very stable strong position with refined products in that section.
We also have an ammonia line, which is a small part of our business there in the Mid-Continent, represented by the purple line. We've also got a network of petroleum terminals in the Southeast, represented by the red dots. They're connected to third-party pipelines that distribute refined products into those markets. And then we have a number of marine facilities in the coast -- on the Gulf Coast in the Northeast. Those are large storage terminals. We typically simply lease those facilities for a fee, and they have a lot of optionality. For instance, our Houston -- our Galena Park terminal has access to all of the refining complex locally in Houston, has water access to all the outbound and inbound pipeline capacity. So the significant optionality around these facilities.
And also, we've built a position in Cushing with regards to crude oil storage. Three years ago Magellan really had no assets in the crude oil space to speak of and we're rapidly growing that. We started that with an acquisition from BP of their crude oil assets in Cushing and a distribution system in Houston. And we're growing that substantially, as I'll talk about here in the slides going forward. Again, this is kind of representing the shift in focus of the company.
We look at 2012, 90% of our operating margin was from refined-products-related opportunities. 10% was from crude oil. If you look at where we're spending our capital going forward, our expansion spending for 2013 and '14 in total is about $1.2 billion, 75% of that is targeted for crude-oil-related projects. 25% is refined products.
We are also working on a whole host of other projects which aren't yet announced yet in excess of $500 million. 80% of those projects are crude oil related. We project when we complete the projects that have under development right now and fast-forward to that point will be about 30% of our income coming from crude-oil-related opportunities.
The biggest projects we're working on are 2 pipelines out of the Permian Basin, the Houston, Longhorn Pipeline, which is an existing refined products pipeline being converted to crude oil. 225,000 barrels a day capacity. That project is fully subscribed. $375 million worth of capital at about a 3x EBITDA multiple. So it's a terrific project for us. That's going to be operational, projected about the middle of next month. So we're getting very close to starting up this pipeline.
And we're evaluating a 70,000-barrel a day expansion on that pipeline. That expansion is really just a permit process. There's the potential that we have to spend no capital to make that happen. And so we're in the process of starting that permitting process right now as we speak.
BridgeTex is a joint venture we have with Oxy. We're both 50% owners. 300,000 barrels a day capacity. Our portion of that capital is about $600 million. That project is not fully committed, but the commitments we do have generate an 8x multiple. So we've got an 8x multiple project with significant upside, and we expect that to be operational by the middle of 2014.
The other thing we like to highlight is what happens once you get to Houston and Texas City. This distribution -- this is a schematic, representing our distribution system, crude oil distribution system in the Houston, Texas City area. Clearly, I'm not going to go through all the lines here, but essentially all the lines on this map are either in service or being constructed right now. This system is going to have the capability to distribute all the of crude oil coming in from our 2 projects from the Permian to the entire refining complex on the Houston ship channel and Texas City. We can get to every refinery pretty much without capacity limitations.
We're also East Houston, which is the upper left hand box there on the slide, is also the origin point for shale host system to take crude oil further east into Port Arthur in Louisiana. Not only that but this system is also connected to the other inbound pipelines into the Gulf Coast. So we've really structured this to be one of the premier distribution systems for domestic crude, once it's arriving in the Gulf coast.
We also just announced, we've entered into a agreement to offload railcars into our Galena Park facility and connect Galena Park into our distribution system, so that the crude oil can be railed into the market also and then have access to our distribution system to touch our refining complex.
And just lastly, we just announced just 2 weeks ago, an acquisition in the refined products space from our friends on the panel here from Plains. And those pipes are the red and blue pipes there on the map. $190 million acquisition that's immediately accretive to us. And you can see that these pipes fit very well with our existing infrastructure.
So I know that's brief but we'll get back, get on with the panel.
Eric Slifka
My name is Eric Slifka. First of all, I want to thank everybody, for their interest here in the midstream space. I think before I start with my presentation, I think Al, Mike did some great summaries on what's taking place in the business and the industry and why we think the midstream space is really in a unique position to take advantage of a fairly rare opportunity.
When you look back at some of these slides that we've already seen today, the growth that is coming in this business is enormous. And the way products have moved through the system historically are being changed because there's so much energy being found. And so what happens is it becomes incumbent upon all of us in these midstream companies to figure out how to get all this new energy to market. So we're really in this great phase of growth businesses, where there's additional volumes to have, and then to figure out how they are going to move and how we can service our customer base by building out the infrastructure to move these products throughout the country.
So with that, I thought I'd just give an overview of Global. So Global is really a midstream logistics and marketing MLP. We're a leader in logistics, transporting Bakken, crude and Canadian crude and other energy products to markets. We have a recently announced acquisition in North Dakota. We bought 60% of 2 transload facilities that take unit trains and deliver them out to both the East and West Coast.
We have connected with that facility, destination point. So we have origination and destination points where we move the products from where the products are being found and we get them to marketplace. On the East Coast, we essentially have a facility in Albany that can do about 160,000 barrels a day of petroleum products. We've been expanding that and recently finished that expansion and are taking in and moving out of there somewhere north of 100,000 barrels a day of products.
Some of the other businesses that Global is in. We have one of the largest terminal networks of refined petroleum products in the northeast. About 10-plus million barrels of storage. We are also one of the largest wholesale marketers of petroleum products. That's heating oil, gasoline, kerosene, diesel fuel and crude oil to the marketplace, and we're also a large retail gas station operator, owning, supplying and leasing recent approximately 1,000 gas stations in that same Northeast region.
The key on these assets is, these aren't in places where you can simply buy land and build additional terminal assets. They're in metropolitan, highly populated marketplaces, where essentially it's very difficult but not near impossible to build out or have somebody compete with this existing storage that's there.
The opportunity here is to take that existing infrastructure and figure out how to redesign it to meet the current market needs of this great E&P boom and expansion that's taking place. Our Albany, New York facility. We started at that facility and had some small rail capabilities. About -- in 2009, we agreed with Canadian Pacific to build that facility out and take in unit trains. At the time, there really wasn't much crude business that was moving. At the time, we were moving ethanol and by unit trains, which is a very efficient, low-cost method that's made up of about 80 to 120 cars per train and we became a low-cost provider and supplier to the marketplace. As the infrastructure play began to mature and as more oil was found, we essentially decided to go into other products
and carry those other products to the East Coast. So we were one of the first companies to start hauling crude via unit train to the East Coast and we started supplying all the East Coast refineries. As part of that, we have to get railcars and we had to get loading facilities and those are the facilities that we purchased in North Dakota.
More recently, we've acquired an asset out on the West Coast, and this is really key because now, as we're building out our system, ultimately what we end up with is a company that can provide our customers with both East Coast and West Coast destinations. And why is that important? We think that those are 2 high priced markets. The barrels have a hard time getting to those marketplaces and frankly, this facility on the West Coast has a very large dock, 1,200-foot dock, can take Panamax size vessels in with some minor investment. And the possibility there is maybe even export as well. So we think that the growth potential on these assets is quite large. And in March of last year, we acquired a chain of stations, about 500 gas stations, all in the East Coast and that fits our terminaling and logistics systems as well for products.
So we have leadership in gathering storage and transportation and marketing of refined petroleum products crude oil, renewable fuels and natural gas. Quickly, even though it's not a physical pipeline, at the end of the day the services that we're providing to our customers which are refiners on the East Coast is essentially a virtual pipeline. We're buying the products, loading them in North Dakota or in the origin points, putting them on the rail and in trains and then delivering them directly to the refinery gate.
138 million barrels a year, 932,000 automobiles tanks of gas filled a day, 18,000 diesel trucks fueled today, 41,000 homes a day of heating oil, were also delivered. So essentially, we're utility in the markets that we're in.
Here is just an overview of the map of where some of our facilities are located in the Northeast. I think if you compared us to any of the other MLPs or any of our competitors, nobody quite has this market coverage in this marketplace with these assets. And if you look down at the bottom right-hand corner of the screen, you can see the high percentages of the market shares just in terms of barrels of total capacity in the markets that we own.
A little more on the supply infrastructure. East and West Coast, limited pipeline access. Very hard to get those barrels out. It's why rail has in fact become such an important way to move it. Like Al and Mike, we think rail is here to stay. It is an efficient, cost effective, timely solution to move barrels throughout the country and throughout Canada to the consuming markets. And there's a real focus to build these systems out and canted to rail. And frankly, you may even begin to see a difference in how products are supplied to marketplaces over time. Typically, 5 years ago, a lot of these refiners were producing and staying close to their markets and we were importing barrels from all over the world. Today, we're a large exporter of barrels. You have your local refiners who are producing and exporting. Some are exporting. But as the rail gets built out, as they become takers of North American, U.S. and Canadian crude, I think you're going to see them maybe canted more to export as well. So you have to also think about and consider how are those petroleum products going to be moved around the map as business changes.
Our assets, here it is, East/West. We're one of the few companies, if not one of the only companies, at least initially, that can material volumes by rail of crude from origination markets to the coast. And this for Global is a big business, right? And I think we're a little early on in this change. I think we've taken a very aggressive stance to it and I think it's positioned us well and these businesses, are going to get built out over time.
Here is another quick view of the system and the set up here. Clatskanie, Oregon is where our facility is on the Columbia River. Like I said, you can take Panamax in there. One of the facilities that we bought in North Dakota is on the BNSF. That's called Beulah. We're in the middle of constructing a 140,000-barrel tank and truck offloading facility, and that facility could be supplied by that basin Beulah facility. And then the East Coast is supplied out of the Columbus facility, which is in the northern corner of North Dakota and that supplies the East Coast.
And just recently, we signed a 5-year take-or-pay agreement with Phillips 66 for 91 million barrels of crude. We think that this is going to be a trend, and those who really have the assets and the infrastructure in place are going to be the providers of the barrels to this marketplace and we think this is just the beginning.
Very quick update. When you look at Q4, how many unit trains we have taken in to our terminal, albeit that's 87 in Jan, and Feb alone that was 81. So we are ramping our business up very, very quickly to take advantage of the capacity that exists in our Albany site.
Our gas station business. It's tough to look at all these red dots, but let's suffice it to say that we're material to the markets that we're in, and we have a large presence in that business as well.
And with that, I'll turn it over to Gabe. Thank you, guys, for your time.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Okay. Thanks for those overviews, and I think we'll proceed into the panel, if that's okay.
Question-and-Answer Session
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
I guess starting into the Bakken, 2 of you have major presences in the Bakken. I'm just curious because there's obviously been a lot of rail capacity potentially being built out in the Bakken and currently there seems to be a pretty decent fight for market share, taking crude out of the Bakken between pipeline and rail, and in particular, I think one of the notable things was watching Enbridge actually lose a decent amount of volumes to rail out of the Bakken last quarter. So I wonder if Eric and Al can maybe touch on what they're seeing in the Bakken right now, whether you think there's a potential for an overbuild in terms of capacity coming out of the region, and how you're facilities might be positioned there? And I may turn to Eric first since you've got away with going last.
Eric Slifka
So there is rail capacity being built out in the Bakken, but I think one of the key points here is they're also finding a lot more oil and crude. So as the facilities get built out, it's about how they're connected into those systems and are they connected to gathering? Are they connected to pipes? And will those facilities have access to all the available barrels? But part and parcel of that is you also want to be able to connect to your destinations and provide your customers with what the highest value markets are, right? So as a buyer of the crude, we're the highest value market today, East Coast, West Coast or Gulf Coast, and how you get it there and can you get it there in the most efficient way? All right. So those are sort of real critical pieces to making sure that, that happens. One of the reasons that we're very positive about our outlook is that we can provide access to both East and West Coast markets, which are those higher valued markets. And at the end of the day, those producers, when you have to buy from them or when you're customer has to buy from them, they'll see the value in being able to move that barrel in different directions, right? And I think frankly, that's one of the reasons why pipes are under a little bit of pressure, right, because pipes go from A to B. They take major capital investments to change them around. So they've got to be situated in just the right place for companies to want to make very long-term commitments. And I think rail, in particular, provides lots of optionality to go to very different directions and different ports in different places whereas, it's a little bit harder for pipelines to give that same kind of optionality. And ultimately, all that means is that the producers are getting a higher price via rail than they would get by going on the pipes. And so fundamentally, there is a massive shift taking place in how barrels move around. And Al said it earlier, he said, everybody talks about Brent WTI or LLS. I think it's going to become more important about the quality of the crude that you have. So that's sort of going to be next step where people are beginning to focus. And then it's also how do you move that quality, right? But I think pipes, unless they can provide value differently, you take enormous risks on because you know that the market is undergoing a large change in relationships, and pricing relationships that were historic for decades are getting blown up, right. So those barrels now move to different places. And to make 10 and 20 or 15-year commitments to say it's going to go from A to B could be a very costly mistake.
Al Swanson
I would agree with what Eric described. Clearly what you're seeing today as producers, valuing the optionality and the market access that rail has for to see barrels coming off of pipes. We're seeing it -- you see it in the Bakken, Gabe, as you mentioned. You also see some in Canada, where the flexibility and optionality that rails provide is what producers are looking for, what refiners are looking for. Clearly, we view at some point in the future, there's a lot of rail capacity getting built in the Bakken. We see rail as a long-term solution there. It isn't a short-term fix for the Bakken at all. There will be a point, fast forward 4, 5, 6, 7 years where rail will have access capacity there. So there will be some battles at some point to source these barrels is as what Eric mentioned. But we believe that for that period of time or in longer that the incremental barrel in the Bakken will be priced to rail, and we think that the logical home for those barrels are the East or West Coast. Again, there's a lot of like product that's being developed in the Mid-Continent area, Eagle Ford, Permian, that will find its way into Cushing and into the Gulf Coast market. The East and West Coast are the ones that really need those barrels.
Eric Slifka
Gabe, I just want to add. The other chokepoints, so even though you may have these facilities all coming on, the other chokepoint is railcars, right because you have to move these volumes by railcars. And that's a massive infrastructure shift. So railcars are very tight. So even though you may have lots of loading capacity, if you don't have the assets to move it, those facilities aren't going to necessarily get used unless they're the low-cost most efficient provider.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Great. Maybe ask the question to Mike. You obviously have 2 very high returning projects coming out of the Permian, but arguably based on where spreads have been even of late, you probably could have asked more from your customers coming from those projects. So if you can talk you just maybe your approach on those projects coming out of the Permian? How you take the returns you want versus the tenure of the commitment from your customers overall?
Michael N. Mears
Well, you're right. I mean, I think if we were starting those projects today, and we had a short timeframe for development, we could probably extract higher tariffs than what we did -- than we have currently in the projects. But you have to look when we started these projects. And we started the Longhorn reversal, probably 3 years ago, even that recently, I don't think the scope of the potential in the Permian was known. I mean, every analyst -- I mean, every forecast that comes out on production really in every basin, in every quarter, it's higher. In some cases it's materially higher each quarter, and that's true to the Permian. So when we started Longhorn, that wasn't widely known. And producers are not -- they're inclined not to make commitments if they don't have to. And so it was a struggle getting commitments. And so that tariff rate was a really a negotiated rate in order to get the project launched. We've got a 3x multiple in that project, so I'm not complaining. Maybe we would've done better but at 3x multiple, from $375 million doesn't happen very often in this space. So we're pleased with that. When you look at BridgeTex, BridgeTex does have a higher tariff structure. Of course the cost structure is a bit higher because it's all a new build. But now you're reaching a point where the market is becoming more competitive. You've got other competitors out there looking at projects, both announced and unannounced. And so you've got to -- even though you may look like you can extract a price higher than you're getting, you're not seeing all the competition that's out there. There is quite a bit of it.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Got it. Al, if I can ask you a question, just in terms of the mismatch that we're currently seeing between the upswing in light sweet production that you had pointed out to with the slide and maybe the refinery capacity and ability to take that crude relative to the investments that some of those refineries had made. I know the crude oil blending is a decent-size part of your business and you're active in it. Can you maybe speak to how much of an opportunity you see that business for yourself and also some of the infrastructure doesn't get built or, for example, if we're really overwhelmed with light sweet crude, how much of the solution blending could be for refineries?
Al Swanson
What I would say is that we do expect that the significant influx and growth of light sweet crude. The refining industry was gearing up to run a heavy barrel, because we weren't going to find anymore in North America, if you think back a few years ago and the marginal barrel was going to be heavy. And so clearly, the industry has changed a lot, as Eric mentioned. And clearly, we're seeing this huge growth. I think you'll see 3 ways of handling this. One is we're going to move light barrels to the market that matters, just like the rail that we've been talking about, and taking light product to the coast. We think that will be part of the solution for dealing with the oversupply of light in an area and the undersupply of light in another area. Blending will be part of the solution as well. But clearly, there's limitations on how much you can blend. You need infrastructure to do it. You need the other great qualities to be able to blend the crude. So there is a lot of complications associated with that. And then clearly, I think over time you'll see where refiners will actually reconfigure and prepare to run a different grade of crude than what they're currently configured for. Again, all of them have, pros and cons to it. What we do see for our business and really for all of us on the panel is a very, very significant logistical challenge and opportunities that as we look at over kind of the next 3, 4, 5-plus years. Because this is something that's on us. We believe you'll see all of the light barrels packed out of the Gulf imports potentially as soon as the end of this year.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Got it. Great. And maybe shifting gears and 2 questions, one to Eric and one to Mike, on refined products before we open up to the audience for questions. Eric, you have mentioned the shifting dynamics in refined products supply. As a huge presence in PADD 1 refined products distribution, I think traditionally you talked about trying to find opportunistic or distressed distillates or gasoline for your customers coming from abroad and elsewhere. Can you talk about how that business is changing as I guess with the survival or renaissance of PADD 1 refineries, given that you're bringing the Bakken crude? And whether you think there will be opportunities in distressed barrels and some of the opportunities you've seen in the past to source refined products to PADD 1?
Eric Slifka
Yes, I mean, just as a general statement, I think what you're going to see is waterborne barrels have a different value than domestic barrels. But that's a different way of supplying the system or supplying PADD, than has been historically for a very long time, right. So as you look out into the future, the fact of the matter is that I think a shift is going to take place in how barrels are supplied. Particularly, you have Jones Act. So that's going to make it hard for material volumes to come from the Gulf Coast to the East Coast. You'll have the East Coast refiners running domestic or Canadian crudes. And I think you'll see their utilization rates go up much higher. But they're also in a position where they can export as well. So it doesn't mean that unless we paid the highest rate, that barrel is going to get exported. So the next sort of distressed or cheaper barrel is probably going to be coming from within the country, in the middle of the country as opposed to imports or just from the coastal refineries. And that's a real material change, and the infrastructure, frankly, is not set up today to handle that change. So I think if you're there and you're building your system up to take advantage of those opportunities, you're going to be able to make a lot of money, right.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
As a follow-up to that, you do have a pipeline and terminaling presence in Pennsylvania. I'm just wondering, there are some pipeline proposals out there that try to bring Mid-Con refined products and barrels further east, and are you supportive of those projects? Have you been looking at projects like that?
Eric Slifka
Yes, I mean, I think at the end of the day there's been lots of discussions about trying to build the pipes. The question is going to be how long does it take? Can they actually get them permitted? In many of the markets that we're in, we're such a large taker of those products that they're going have to come talk to us and we're going to have the say in taking the barrels from that direction. But even then, there's not an efficient way today to move barrels, particularly products from the West to the East Coast, which is where we're located, right.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
And then, Mike, in terms of your system, traversing basically the entire midsection of the country on the refined products side, with Mid-Con refineries running at such high utilization rates you've commented on the fact that your system is seeing a little bit less in terms of the way of sourcing barrels from PADD IV to PADD III -- I think I got that right, or PADD III to PADD IV -- from the Gulf to the Midwest. Can you talk a little bit about that dynamic, whether you're kind of agnostic to it? And also you converted Longhorn to crude oil pipeline service. Do you see a potential for any other areas of your system in the refined product side of things to convert to other services, whether liquids or crude oil?
Michael N. Mears
Right, I mean, we are seeing a shift in the way refined products are moving just in the last few years. And historically, that deal has been short refined products and that supplemental barrels come from the Gulf. The past 3 or 4 years, we've seen very little of that. The Mid-Continent has been pretty balanced with regards to refined products. And in the last year or 2, we're actually starting to see that shift. And last winter, for instance, gasoline demand is typically low. Mid-Con refiners have astronomical frac spreads with the discounted crude oil in the market, and they're all running at high utilizations, and yet there's no place to put it. So we filled up on gasoline last summer. It created a problem for us; it created problems for refiners. So for the first time ever this winter, we actually were pumping refined products from Oklahoma South into the Dallas market. And we just did that for a few months this winter. I would expect that trend to continue as the link of refined products in the group continues, particularly on gasoline. And gasoline demand is expected to have a slow decline. As long as the refiners continue to want to run at high utilizations, that problem is going to exist in the winter. We've got a system that's well adapted for that. I mean, We've got pipelines that run north and south from Houston to the Canadian border, and reversing a pipeline is not that complicated. I mean, you can't do it overnight unless you're set up to do that. But we're modifying our system so that they can be reversed and start shipping barrels south into those markets. The net result of that is it pushes more barrels back into Houston, and those refiners can export it. We are not currently looking at converting any more pipes to crude oil. Most of our pipes are fairly highly utilized for refined products. There's not an incentive to shift them. They really don't go into the basins and they're really not of the size necessary to make any real sense for crude oil. There may be some odds and ends we look at, but not on any large scale.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
And I think we had a microphone walking around. So if you have some questions, please feel free to raise your hand. We've got one in front here. Mr. [indiscernible].
Unknown Analyst
A lot of great detail there. We haven't talked about much about the economics of moving crude East and West. And obviously, I'm more interested in the refiners economics, if you like, and their range I think has been somewhere between $10 and $18 a barrel on rail. So if you guys maybe talk about what you're seeing in terms of how the trends and tariffs are moving. And if I could also change direction and talk about activity levels from heavy oil in Canada moving to the Gulf Coast, what you're seeing there in terms of again costs and demand, I guess, from the Gulf coast refiners.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Maybe we'll start with Al, if that's okay?
Al Swanson
Sure. I think would agree with kind of the cost estimates that you described, kind of $10 to $18 depending on the movement and the quantity, depending on how you can cycle your railcars and loading and unloading fees, how your contracts are structured. Our view is -- take the Bakken as a the easiest example. We think rail set the pricing at the wellhead in the Bakken. And so in essence, your effectively, as we get more and more rail capacity developed, both the loading side but also as Eric mentioned, on the unloading side, ultimately that will set the pricing at the wellhead because there will be enough people competing for those barrels in the Bakken itself that will be looking at the rail economics to get it to market. And so while it's a significant cost, that's where the barrel will have to go. Otherwise, it isn't going to move. As far as we're seeing in Canada, volumes come off, we aren't actively moving barrels from Canada down. We're seeing others do it. We do think there's a lot of sense to take certain grades of Canadian crude down to the Gulf Coast. There may be some other markets that it makes sense to take that crude to as well. Clearly, some of the heavies up there get very discounted at times. We don't think it'll be necessarily the significant volumes like we're seeing out the Bakken because there is going to be a decent amount of pipeline capacity as all these projects get developed. But we do think there will be some opportunistic movements, the Gulf Coast being one of them.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
And Eric, I don't know if you want touch on that maybe too?
Eric Slifka
I think generally, directionally, you're right. I mean, that's how product is going to move. And the cost really is what can you lay a barrel into the East Coast for or the West Coast versus the alternatives? And the reason the move works is because as long as you can lay it in cheaper than on the East Coast, you're market would be Brent, which is internationally priced and high priced. That's all you have to do to save your refinery money on the East Coast. If it's A&S on the West Coast, then that's your marker there as well, right? So as long as you can move barrels cheaper than what the international market is to the East or to the West Coast or to any market, what their alternatives are, they're going to be a buyer and a taker of the product. And so it's not because the system's out of balance because trade flows are shifting and changing. It's not about what's the spread of Brent-WTI anymore. It's what's the highest and best priced alternative for the producer, right? And that's where the products are going to flow.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Have other questions out there in the audience?
Unknown Analyst
Just shifting gears a little bit. There's always from time to time discussions about MLPs tax status. I guess there was some flurry, of course, yesterday about the ways and means coming out with a bill. Can you comment on what you think might happen here?
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Who wants to take that? Mike? Okay, so you can go first.
Michael N. Mears
I'll start with that. I think there's been some noise about that for quite some time now. As an industry, and Magellan specifically, we're spending quite a bit of time with Congress educating them on the benefits of the MLPs. Why they were set up in the first place, the need for them. The relative tax benefit is not large to the government, how to change the structure. The fact that you've got a large retail investor base that relies on the income from MLPs, there's a lot of positive reasons not to change the structure. We talked to members of the Ways and Means Committee. The feedback we get is, we're not the target. They understand the benefits. I think there's been some concern. We've heard about some of what their words described as exotic MLPs that are coming into the space. So we think it's more likely than not that we are safe from a change. I mean, I don't think the risk is 0, clearly. So we can just continue to educate them and stay available to talk to them so that we get the right outcome.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
And just to be clear, Mike, Magellan, Plains, and Global, are the farthest things from exotic MLPs, not to anyone out there, right? Any other questions out there? I've got another one if nobody else has any. Just curious in terms of the incremental project that you're seeing out there on the crude oil side for rail and pipeline. Who is the customer at this point on the incremental customer? Is it the refiner at this point? Is it the producer customer? Have you seen a mix in that shift over the last year or 2 based on projects? And maybe I'll start with you, Eric, if that's okay.
Eric Slifka
Yes, I think that the taker, right, the refiner is the customer that is looking to term up and make the investment to take in that crude because it has so much value to them. The producers, I think if they felt like they had the right market and the right asset and the right infrastructure to go through, they may commit. They may, right? But to date they haven't been the big ones to commit to the projects. But I could see that changing over the next 12 to 18 months.
Michael N. Mears
I think our experience is we've got a blend, a pretty balanced blend of refiners and producers and a handful of marketers, but predominantly, refiners and producers. And I think we're a little different in that our projects are going to the Gulf Coast. You've got a large, diverse refining complex down there, which I think the producers are feeling more comfort they can sell their barrels in that market than going to a market where there may be 1 or 2 refiners to sell from, but we've seen a blend.
Al Swanson
Yes. We have as well. We've seen significant interest in some of the major producing areas on the producer side. If you back up 3, 4, 5 years ago, I think Mike touched on in his presentation that producers were, I can say, took the midstream side of the business for granted. I think what we've learned is that there's much more need to make sure you have the market outlet. Again, in a lot of these producing areas, the person who bears the brunt of not having that midstream infrastructure is the producer. But as Eric mentioned, we are also seeing interest in refiners trying to make sure that they have access to the lowest cost feedstocks. So we're seeing a balance as well.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
Okay? Any more questions? No one wants to ask the panel to take a bet where Bakken -- or WTI-Brent is going to be in 2015? Come on, nobody one wants to try? How about that one? You want to ask? Okay, all right. Well, let me ask then. So If you guys have your best guess, in terms of thinking about WTI-Brent in 2015, go for it and why.
Eric Slifka
Hey, Al. You're moving 4 million barrels a day, okay?
Al Swanson
Our view is clearly, the wide points that we've seen to date we don't think will be here longer term. Although we don't think we'll move back to where we were prior to kind of the significant change in the supply domestically. We think you will see a differential between Brent and LLS. You may see the differential between LLS on the Eastern Gulf to the Western Gulf. And then you're going to see a transport differential going back up to Cushing. So I would expect to see a range that's more in the mid-single digits, call it a $6 to $8 type of differential is what I would expect to see it normalize into, not to say that there won't be periods of time where it will go outside of it, but that would be our view.
Eric Slifka
I think it's important to remember though, for all of our infrastructure businesses, we are moving physical volume. So everybody gets focused on the spread. But that's actually not how the barrel moves. The barrel moves by what the producers sells it at and what the consumer buys it at. So at the end of the day, whether that spread is $25 spread or an $8 or a $5 spread, the infrastructure that gets the volume to market, which is our companies, is going to move that product one way or the other, and that's really the critical piece. So could that spread be $8 or $12? Sure.
Michael N. Mears
Yes, And if you take it one step further, if WTI to a LLS or a Brent price comes in to that mid-single digit but yet if you go back to the Bakken, today when those differentials are, say, $17 to $20, the Bakken is trading on top of WTI. Because the bottom line is it can because the other differentials is so wide. If the WTI to the Brent coming in, what you will see because again, the barrels won't move out of the Bakken unless it's supporting rail economics. So that's $17 you're going to see the Bakken the WTI widening back out. So there's a lot of interplay between the differentials.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
We've heard a lot today about the refineries backing out international crudes, and you mentioned that you think that as early as end of '13 that you might see LLS or some of the international crudes backed out of the Gulf on the light side. After you see that happen and with all the infrastructure coming on to move from Cushing down to the Gulf, I mean how do you see it playing out from that point forward, let's call it '14 going forward? And where does that go and what happens to all the infrastructure? Will we see utilization drop as additional capacity comes on? Or how do you guys see that playing out?
Al Swanson
I guess there will still be a significant quantity of crude oil being imported into the Gulf. So what we're talking about is backing out kind of the lighter, sweeter barrel. In essence then, we think we're going to see some of those barrels move further East in the Gulf, potentially around to the East Coast. Again, I think you're seeing people trying to make sure they have optionality and not send the light sweets out. And so you'll likely see some refiners look to try to configure to run the lighter grade. You'll see some blending. So I think it'll be kind of a combination of all 3 things I kind of described to deal with it. From our view it creates a logistical issue because, as Eric mentioned, they're physical barrels. Ultimately, we are going to move them to the best market. And again, a refiner probably won't make the investment unless they feel like they can get a return on it. But it will affect the way these barrels are directed and moved. And it's one of the reasons why it isn't logical but the natural flow plain of taking a Bakken barrel south really doesn't make sense longer term.
Michael N. Mears
I think, I mean, it all drives up to the ultimate question to at some point in the future is what we do with export capability in this country. Obviously, right now the presumption is it's not allowed. The problem hasn't been an acute problem for quite some time. But as we reach these production levels and we reach this supply and maybe long and light crude domestically, that question is going to become more acute. I can't predict what's going to happen there. But certainly, that's a step function change in the market, if it were a change such that, that would be allowed. Clearly now the changes the dynamics of everything that we were talking about.
Gabriel P. Moreen - BofA Merrill Lynch, Research Division
I think we're about out of time. So I appreciate everyone's attention. Thank you to our panelists. And thank you. Thanks, everyone.
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