Magellan Midstream Partners, L.P. (NYSE:MMP)
2016 Analyst Day
March 31, 2016, 09:00 AM ET
Paula Farrell - Investor Relations
Michael Mears - Chairman, President and Chief Executive Officer
Jeff Selvidge - SVP, Refined Products
Robb Barnes - SVP Commercial, Crude Oil
Aaron Milford - SVP and CFO
Mark Roles - VP Commercial, Marine and Commodities
John Edwards - Credit Suisse
Faisal Khan - Citigroup
Elvira Scotto - RBC Capital Markets
Shneur Gershuni - UBS
Jeff Birnbaum - Wunderlich
Steve Sherowski - Goldman Sachs
Shneur Gershuni - UBS
Good morning, how are you all today? My name is Paula Farrell and I am responsible for Investor Relations at Magellan. And we appreciate you spending your timing with us today for Magellan 2016 Analyst Day.
The last event we held was two years ago in 2014, obviously the environment is a bit different than it was back then, but we hope for today words that we talk with you about that you will see that it reinforces the message of the stability, the consistency and the growth potential that Magellan continue to offer even through these challenging times.
I’ll go ahead and go real quick with you through the agenda for today and then we will go ahead and get started. We will start off with Mike Mears, who has walk through kind of our proven track record, how Magellan has done to stability part that we talked about a few minutes ago. From there we will have each of the folks that responsible for our commercial group, talk about the instability of our base business. Jeff Selvidge, who right away here just could stand up please, will be walking through refined products in the marine storage segment for us. Robb Barnes will be talking through our crude oil segment.
We will take a short 15 minute break at that point in time. Then Mike Mears, I think you all know and our CEO will talk again about kind of the future growth opportunities that we have in front of us. Aaron Milford who is here at the front as well will walk us through our finance review. And then Mike will wrap this up with a few closing remarks. After that we will have lunch for those of you who are available to stay with us and we will have Magellan Management throughout the room.
Actually in saying that we have a few other members of management, I would like to - standup as I mention their names, just seeing who else this year from the company. Looking at the bottom row, we have Stan Roger, who is in the back, he is our Vice President of Commercial for the Refined Products Pipeline System. Mark Roles this year as well, he is also on this side, he is responsible for Commercial, Marine and our Commodities activities. Bruce Heine may still be out and chatting with folks, he is our Director of Media and Government Affairs. Jeff Holman is our Vice President of Finance, he is also in the back, he is our Treasurer as well. And then Michael Aaronson, here at the front is our new Senior VP of Business Development. So that’s the management team that we have here and again they will all be here at lunch. So we hope you can stay with us for that.
Before we get started, obviously we do have our Forward-Looking Statement disclosure, obviously everything we are saying today is based on our current best estimates. We do ask you to make own judgment in making decision about Magellan. One other thing I would like to walk through just real quick is how we plan to handle questions and answers, we have designated spots after each speaker, Jeff Selvidge since he has two business units that he will be covering, has two Q&A segments. And so Linda and I will be walking around with microphone during that time, if you would like to ask questions we would be happy to take them at that point in time.
And with that we will get start with Mike Mears, who is our Chairman, President and Chief Executive Officer and again we appreciate you being here today.
Thank you Paula. I would like to welcome you too, I think we’ve had a great turnout today. It’s good to see all of you again and we think we’ve got an exciting story to tell today. I was just going to highlight a little bit and you probably noticed some of those folks up there are new to their position, senior positions within the company. They weren’t here at last analyst meeting we had.
All of these folks have had moved up through the organization overtime, so I would like to highlight that because we don’t often go out and hire, we don’t bring in new ideas kind of change our business strategy, these are all folks that have been with the company for quite some time. And have moved up through the organization to maintain the consistency of the culture and the business plan for the company.
And I want to thank Paula too for putting this together, first of all to this lot of work that goes with this, so thank you Paula and Linda, I think she is outside for everything they have done putting us together. Paula mentioned the kind of the theme you are going to hear a lot today stability, consistency and growth. In fact, I went back and looked at the transcript for the last analyst meeting two-years ago. On the opening remarks and I thought I could probably just use this exact same presentation, because it hasn’t changed.
I mean We have implemented, we have executed the way we said we were going to and the results have been similar with regards to performance. So it’s not just a catch phrase when we talk about consistency and stability, we really try to practice that. So with that and I’m not going to spend whole lot of time on our history and where we are at right now, because most of you are probably very familiar with that.
But just a few points, this is our distribution growth sense inception since we spun out from Williams in 2001 and then subsequently went public as Magellan in 2003. Pretty strong track record 13% compounded growth over that time period with regards to distribution growth 55 quarterly increases over that time period and this is over - I would like to point this out too, since 2001 this is through a variety of operating environments.
We went through a recession during this time period, pretty significant recession, we’ve gone through a number of commodity cycles including the one we are in right now and we have been able to maintain a very strong and consistent growth profile regards to our distribution history. And still with that going forward, we are guiding to 10% distribution growth this year and at least 8% distribution growth next year.
And we have done all that without stressing our coverage, we expect to be at 1.2 time coverage this year and next year, even with the distribution growth targets we’ve communicated and we haven’t stressed our balance sheet, we still have a very strong balance sheet and Aaron is going to go through that in financial section. So we think we’ve got a good track record with regards to performance, with regards to consistency and growth.
When we look at our total shareholder return or total unit holder returns since 2010, you can see we’ve done very well versus the market. Almost got a little over 200% since 2010 versus the index which is generally flat. How do we do that? How does that happen? I think there is a lot of elements to that but if I could boil it down to two things. I think first of all as we stuck to our business plan, we’ve continued to invest in well positioned, strong fee based businesses.
And number two is what we haven’t done, we haven’t participated generally in kind of what I would call the feeding frenzy of acquisitions that was occurring during this time period with the low cost of capital, the abundance of cash in the market and the resulting high prices in our opinion that people are paying for acquisitions. We resisted that we exercised discipline to that market and I think a lot of people are being affected by that now and were not to a larger sense because we didn’t participate in that during that time period.
Our cash flow, DCF cash flow growth over that same time period from 400 million to last year we were at 943. Again, the story is the same investing in goods solid projects and we’ve done this generally speaking as I said, without stressing the balance sheet. We only have one equity offering this time period, in 2010 we did it 250 million equity offering, we haven’t done $0.01 as Aaron will talk about here in a minute. We don’t see the need to do one anytime in the forcible future. In fact, that’s the only equity offering we’ve done in the last 12 years. So we’ve been able to build this business and grow our cash flow with our balance sheet, because we are investing in good projects which increases the borrowing capacity and or retain cash flow.
You can see where that growth has come from, primarily it’s come over the last five-years from our investments in crude oil. That’s I’m sure no surprise to anyone, on our crude oil business five-years ago was essentially non-existence and now it’s 30% of the business. So that’s where the predominance of the growth has come from, but we still have growth in other areas our base business we’ve grown quite a bit, refine products growth we’ve stepped outside the box little bit and grown that business and our commodity business has grown. And I want to point out that growth in commodities is not all just margin driven. We’ve done a lot of work to improve the efficiency of our butane blending and make sure were maximizing the volume opportunities associate with that business and that’s a significant portion of that commodity growth percentage overtime.
As we get forward in this presentation, you will see that that our expectations for that growth we expect to become a little more balanced going forward, but that’s where they have been for the past five years. We are still guiding to $900 million of cash flow this year, when we issued that guidance back in February, I think we were communicated some of the underline assumptions there. In our view, they are very conservative assumptions, one of those assumptions was crude oil strip for 2016 of about $35. We’re above that right now, so obviously that’s directionally positive but just too early in the cycle for us to make any adjustments to our cash flow guidance for this year, so were just reaffirming the $900 million at this point.
Again, this is a slide that probably hasn’t change much for five plus year with regards to the mix of our business. We’re 85% fee based, most of that is transportation related tariffs on our pipelines and we have a number of items also , a least storage, terminal fees, blending fees, ethanol fees those sorts of things that Jeff and Rob will go into more detail here in a minute. And then the commodity related activities which is about 15% of our business, which again is primarily butane blending. But again, it just goes back to the consistency of executing our business model, but that you don’t see this mix change dramatically year-over-year. In fact, you may not see it change at all, this is pretty much what they spend for quite some time.
If you look at our expansion capital spending overtime, since 2006 $4.4 billion we’ve invested. The green bars here are organic projects, the orange bars are acquisitions, you can see the predominance of our spending has been on organic projects and I can say with certainty that every acquisition we’ve done internally we’ve used those as being successes. In a market where I think the specific shows 70 to 80% of all acquisitions on a financial basis are not successful.
I think we can honestly say that every acquisition we’ve done over this time period we’re very pleased with the financial results. And that doesn’t happen by accident, that happens by being disciplined and only executing on acquisitions that make sense for your business and do not have a significant - in our view you are not overpaying for and do not have a risk profile that doesn’t fit well with our corporate strategy. We have $900 million of capital spending for this year and next year for projects that are being constructed right now.
I’m going to go through those in greater detail after we go through the base business presentation. And then as we say, frequently we’ve got over $500 million of potential growth projects. I’m going to talk a little more about that a little more color on that than may be we have in the past on some specific things we’re working on, but I’ll do that here in the future also, after Rob and Jeff go through their presentation.
And so just to lay again the foundation for the rest of the presentations on the base business, we’ve got, one thing to highlight as we go through those base business the stability of the cash flows that are underlying those businesses, discipline and opportunistic investments on our organic and acquisition, we’ve got a very disciplined financial policy which Aaron will go through. And as always, we strive to be a key business partner and strong operator with all of our customers and we reap the benefits from that.
So with that I’m going to turn it over to Jeff Selvidge and we’ll dive right in to the refined products business.
Thanks Mike and good morning everyone. As Mike said, my name is Jeff Selvidge, my team is responsible for the commercial activity on the refined product and a terminal - marine terminal areas. I’ll walk you through those business segments, we’ll talk a little bit about the asset, show you some numbers historical and projected and then talk a little about business strategies and some of the business drivers we see for these assets.
This is a map of the asset contained in the refined product business unit, the green is our central corridor pipeline network, the green dots are the terminal connected to those pipes. The purple is our ammonia system and then the yellow dots in the southeast is our independent terminals network. Not shown on this map is our commodities business, which stretches across all of these assets with the exception of course of ammonia there is no commodity activity at this stage with ammonia.
Just some high level comments on refined products. It is our largest business unit, in 2015 we were a little over 60% of the Op margins for Magellan. Most of the profits come through pipelines and terminals and the business model for that is fairly straightforward, it’s volume times rate whether it’s a pipeline volume at a tariff or a terminal volume at a terminal rate. We also have though built a nice book of business around ancillary services, they are still fee based but they are in addition to the base business of tariff and term loan fees.
And then we’ve added to that our commodities business which we’ll talk about in a little more detail. When you think about our commodities business though at just the high level, you can think about spread between gasoline and butane. It’s a little more complicated than that and we’ll go through some of that for you, but just in general that’s the driving factor behind our commodities business.
We’ve laid out in this table some statistics for you. You can see on the volume side 2013 to 2014 we had a nice growth in volume, these are our pipeline shipment volumes. 2014 to 2015 we flattened out a bit due in most part because of the drop in crude prices, the drop in drilling activity, which affected our distillate volumes in some of our larger markets. You can see we’re projecting a nice rebound to 2016, 485 million barrels at the 7% growth in part because of some of the projects we’re bringing on like our Little Rock pipeline projects.
And just to put that in perspective for you, $485 million that’s a little over 1.3 million barrels a day, when you add our terminal volumes in there in the southeast that takes us up over to 1.7 million barrels a day so fairly significant part of the U.S. energy infrastructure. Like Mike I look back at the 2014 transcript, that number in 2014 is 1.5 million barrels a day. So we talk a lot about crude and rightly so I give Rob a bad time about stealing all the headlines but refined products has increased over 200,000 barrels a day since we last talked to you.
We show you our transportation rate per barrel. The Op margin again, following that model of volume times rate has the same per trend that our volumes does, we’ve flattened out a little bit in 2014 to 2015 and then we’re showing a nice rebound in 2016. Our product margins again follow that commodity curve you saw a nice growth 2013 to 2014, 2014 into the start of 2015 and then we began to follow the crude price back down in 2014, our estimates for 2016 is a $149 million in commodities and again we’ve got some slides here, a little later to highlight that.
Talking a little bit more about the assets, we can start with the refined products pipeline system at just under 10,000 miles of pipe, it’s the longest petroleum pipeline in the U.S. We have 54 direct connected terminals to our system that number was 53, but in anticipation of our Little Rock startup we’ve moved that terminal from our independent group into the pipeline group. And just a word on terminology, we talked about terminals on the independent side, we talked about terminals on the pipeline side.
The distinction there is the pipeline side they are connected to our pipes, the independent terminals are not, they are connected to third party pipelines. And on the connected pipes those fall into two groups. Those that are bundled in with our tariffs so we don’t charge a separate terminal fee and then we have a group of terminals that are not bundled in and so when you see our ancillary services you’ll see a sliver of revenue for terminal fees as well.
You can see from the map we cover a large geography basically from the Houston Gulf Coast to the Canadian border, Chicago and then west over to Denver. We’ve accessed either directly or indirectly to about half of the refining capacity in U.S. and really when we talk about competitive strength that’s one of our biggest strengths, it’s just a breadth of coverage, all of those pipes that you see on that map are interconnected in some form or fashion. And really when we go talk to customers and when customers decide who they are going to do business with.
This is a big advantage, because if you are a refiner in Houston and you want to sell into the Texas market, you want to sell into the group markets you want to go out to Denver. You can do all that through Magellan. Likewise if you’re a gasoline supplier in Des Moines, Iowa you don’t have to just use regional supply, you can bring barrels off the Gulf Coast, you can bring barrels out of West Texas, Northern tier. So we offer a lot of flexibility and diversity for people and so as supply patterns change as kind of regional disruptions occur, people are able to react and stay on the Magellan system to supply that market.
The other advantage we think we bring to the market is of independent service provider model. We talk about this a lot, it’s been a consistent theme of ours through the years. Quite simply, we just don’t compete with our customers and the feedback we get is that that served us very well, customers want to know they are doing business with somebody who’s incentives are aligned with theirs. So I think you’ll see that continue into the future.
We talked about the geography, can give you a little color around that. The pie chart there on the left shows our deliveries broken down by state, you can see that Texas was the largest delivery point at almost a third of our volume. Minnesota, Iowa, Missouri, Oklahoma those are also large states for us. The bar chart on the right is interesting as well. That shows our market share by state and I guess the takeaway from this is in almost half the states we operate we have a market share of 40% or greater kind of underscoring our significance to that central energy corridor for the U.S.
When we talk about stability we are a demand driven system, but we do have a contracting strategy that goes along with that. Unlike what we might see on the crude side where they have a lot of take or pay, underwrite a large investment out of a basin. Ours is more of a decision of optimizing guaranteed demand versus price, so we’re constantly trying to reach that perfect balance in how we contract. As a result of that in 2015 about 40% of the volumes we delivered were subject to some sort of supplemental agreement.
The pie chart here on the right we’ve broken those down for you by type, just real quickly market share agreements are a smallest that’s the purple slice that’s just where our customer agrees to give us all their business in the Kansas City market for example. Take or pay we do have some take or pay agreements if we made an investment such as an additional slot on the rack or horsepower to a given line and we feel like we need to underwrite that with a specific customer or customers then we’ll enter into the take or pay.
The biggest tranche is about half of our agreements are volume incentive, those are simply a commercial tool that we can use to exchange price returns. And so if you roll that all together the average term, length of term for the 40% of the volume we have under contract is about four years.
Let’s talk about rates a little, one of the determinants of our revenue. You know all I think you guys know all of Magellan’s rates are regulated in all the markets and all the pipeline markets we operate in. Under the current regulatory framework they fall into either one or two categories, either - I’m sorry they are regulated either at the Federal level by the Federal Energy Regulatory Commission or the FERC or by some state equivalent of FERCs such as the Texas Railroad Commission.
And then the FERC puts those into two categories, either workably competitive which I think shown here in blue I hope that’s showing up, those are the markets that FERC has deemed workably competitive and basically they have made a determination that they are sufficient competition in the marketplace to regulate price such that they don’t need to. And so the market has allowed to set the price for the service. In 2015 about 60% of our volume was delivered through market base rate. The other 40%, which shows up here in yellow are deemed less competitive and just as the name implies the FERC still feels the need to regulate the price in those markets and they do that through their FERC index.
The index is well I’ve got a slide here next. So the way we determine our price changes for market is we follow the index on the less competitive and then we make an annual decision on what we’re going to do in the less competitive. In the more competitive market based on market conditions. In recent years those have both been the same just because the index has been so healthy, we’ll talk here in a minute 2016 we’re probably going to vary from that policy.
The index itself just in the way of background it was instituted in 1995 by the FERC, it was put in place to really simplify the regulatory process to give pipeline an opportunity to recoup their cost and gain a - make a reasonable return on their investment and really simplify it outside of a complicated and lengthy cost of service filings. So their methodology ties it to the PPI the Producer Price Index and you can see the box there on the right, it’s reviewed every five years and the adder to PPI has changed based on the previous five years data.
The bottom line in the box you can see where we’re at in 2016, this was the first year of the next five year cycle. The FERC has determined that the index will be PPI plus 1.23%. That’s down from the previous adder of plus 2.5% and there is some technical reasons as to how the FERC evaluated the data that I won’t go into here, we can talk about at lunch or break if anybody is interested. What that means for 2016 is PPI is expected to be a negative 3.2% when you add the adder to that that makes the index just below negative 2%. We are going to raise our tariffs in our competitive markets. We’re not going to take the index we’re actually going to raise the rates, so when you roll that altogether we expect about a 2% increase in our rates across the system for 2016.
And then sticking with rates, we report and we talk in earnings calls about rate per barrel that’s just the average rate that we make on a transportation barrel on a system. The bar chart here shows you what that rate has been and what we project it to be for 2016. The redline is our total rate per barrel, the blue line we’ve extracted out some of our South Texas movements and the reason that’s material is those are large volumes, low tariff rates so it tends to skew the number down.
You can see in from 2015 to 2016 we’re dropping a little bit on our average rate per barrel a penny or two. That’s not bad news, because we’re adding volume to the system so we’re adding incremental revenue but they are at a low rate which is tending to bring that overall rate per barrel down slightly. And just as a note when you look at our financials and you hear us talk quarter-to-quarter, this number can bounce around a little bit on a temporary basis. If we have a refinery go down or go down on maintenance or we have a disruption on our system then you can see that rate per barrel bounce up or down, but it usually comes back to the historical average that that’s just a temporary phenomenon that we might see that will affect the rate per barrel.
Moving on to volumes which again rate times volume is what we focus on, we generally trend since we’re demand driven, we generally trend with the refined products demand in the markets in which we serve. As I mentioned earlier, 2015 was flat to 2014 that was due to the drop off in drilling activity that reduced our volumes in places like Odessa, up in the Dakotas and Oklahoma and so while we saw 5% higher gasoline volumes due to lower commodity prices, we also saw that was offset by 7% lower diesel volume. And then we’ve got some color around what happened in 2013 and 2014.
As I mentioned though our volumes are - we plan to bounce back pretty nicely in 2016 we think our base volume will be up about 1% and then when you add our growth projects in such as the Little Rock pipeline, we’re projecting a 7% growth from 2015 to 2016 on refined products volumes. The pie chart there at the bottom just breaks that down for you by product group.
Longer term, which are not in our 2016 projections but when we look at longer term we use EIA projections, which is Energy Information Administration I believe the government’s forecasting arm. You can see from the curve that they forecast over the long-term a slight decline in gasoline volumes as fuel efficiency overtakes vehicle miles driven and then they show short-term increases in diesel volumes flattening out over time. I will say as we view this for a number of years and compared it back to our historical EIA tends to be a little more bullish on the decline of petroleum fuels, we’ve not seen exactly what they forecast. We agree with the trend, it’s just a matter of time and magnitude, so.
So that’s it for the pipeline tariff volume, as I mentioned we’ve added a nice book of business on fee based revenue, ancillary fee based revenue that we see along with our transportation revenue. The pie chart at the bottom just to give you some numbers that our tariff revenue is about $625 million for 2015, our fee based business is about $350 million so just under a $1 billion in revenue associated with that segment. The pie chart to the right breaks down those fee based revenues and I won’t go through all of those, but just to make a couple of points again the blue slide up there at the top is the terminal throughput. That’s for those terminals that are tied to our pipeline but are not bundled in our service. So there’s an additional fee to go through those.
Ethanol, that’s not a commodity related activity that’s just our storage and throughput fee for ethanol. Our projections and what’s in our forecast as we don’t see ethanol going above 10%, we just don’t see the market acceptance to that at this point. And from a fee standpoint our storage and throughput fees are similar to our tariffs, our average tariff so whether somebody moves a barrel of gasoline all the way through the brack or blends it with a barrel of ethanol will relatively in different from a revenue standpoint.
One change you might have noticed is the light blue or purple sliver up there at the top called tenders. That used to show up in our operating expenses, it’s now been reclassified as a revenue, tender deducts are what we take off of every shipment. Every shipment that comes into the system we take a tender deduct to compensate the carrier for interface losses, measurement issues, evaporation, things like that. And that varies from either you know anywhere from one twentieth of 1% to one tenth of 1% depending on which system you’re talking about. Net revenue line is directly tied to a commodity curve.
So that’s it for the pipelines and terminals, talking a little bit about the other two asset groups within the refined products group showed you on the original map our independent terminal group located in the southeast, there are 26 terminals, they are all connected to either Colonial or Plantation, about half of those are connected to both. You know the competitive advantage is we feel Magellan has is much like we talked about on the pipeline side.
We have a very broad network here across the entire southeast region. So when we’re talking to customers who have terminals in multiple markets, or demand in multiple markets to make use our facility. It gives us the ability to aggregate volume and really contract that altogether and so that’s a big advantage for us for the customers kind of a one-stop shop, they don’t have to bounce around from terminal-to-terminal and system-to-system.
Also our independent service provider model again across all of our assets we think this has been a big advantage. In terms of throughput we’ve grown these assets very nicely, you can see at the bar chart on the bottom. Since 2013 our estimate in 2016 we expect to eclipse the 400,000 barrel a day mark this year. That’s about a 23% increase over that time period. We’ve done that both through acquisitions, we acquired a terminal in Roanoke, Virginia in 2014 and last year we acquired a larger terminal in the Atlanta area. But we’ve also grown our base business, when you look at that 23% it’s about a 50/50 mix between acquisitions and base volume growth.
As far as contracting strategy we do have a large volume of our throughput under contract in the southeast it’s a very competitive market you see that number a little higher than what you might see on the pipeline side. And in 2015 it was 75% of our volumes going through the terminals was under a customer’s commitment. We don’t talk about the independent terminals a lot independently, or outside of the refined products group, but just to give you a perspective they out margin these assets generated in 2015 of $35 million.
And there is - also we do butane blends, we have terminal overages at these facilities so that piece shows up in our commodities revenue but if it was allocated to the independent terminals that’ s about another $20 million. So all-in this is about a $55 million contributor to our bottom line for refined products segment.
The last asset group in our refined products segment is ammonia pipe, again this one we don’t talk about a lot about separately. For those of you that have been following us for a while we used it have it broken out as some segment but with the growth of Magellan it just didn’t make sense any longer, so we rolled it into refined products group which fit geographically and more in line with how that revenue earned. It’s an 1100 mile pipe, you can see the routing of it here on the map to move ammonia, which is a fertilizer made from natural gas, we move that from a producing plant in Oklahoma in Texas up to the consuming regions in the upper Midwest.
The pipe supported by three year take or pay commitment, they roll from year-to-year with three year life. This year we expect to move about 770,000 tons fertilizer is moved in tons rather than barrels, don’t ask me why, but there is a conversion that gets you from tons to barrels if anybody is interested. Our contract allow for escalation by the FERC index we do not however have to take our rates down when the index is negative such as this year so those rates will remain flat.
Our expectation for revenue over the foreseeable future is pretty flat. Again, we feel very confident about the financial health of those plants given the low cost of their natural gas feedstock and the demand for fertilizer and our transportation rates stack up well with their alternatives from moving fertilizer into the upper Midwest. So again, we don’t break it out, but just for reference the ammonia system in 2015 generated $19 million in out margin.
So that’s it for the assets. There is one other compound out of our refined product segment that we wanted to touch and that’s our commodities. Magellan is primarily fee based but we do have 15% of our less or do expect 15% or the less of our future Op margin to be generated from commodities. And when I told you at the start to think of commodities as butane minus or gasoline minus butane, this pie chart shows you why. On our commodities for 2015 for example, we generated 197 million in Op margin, 92% of that came from butane blending. So we do have another a couple other small activities in there, a fraction there is in our terminal overages but year-in and year-out the profitability of this piece of our business is driven by butane blending.
So we can talk a little bit about butane blending sure you guys area all familiar with butane as the common gasoline blend stock, it’s a hydrocarbon used by refiners and gasoline blenders to trim blend gasoline. Butane historically is priced below gasoline and in recent years significantly below gasoline. The blending on our system occurs really in two areas. We have custody of a large fungible approval of gasoline, often times that gasoline comes into our system below the quality standards that we set at the origin and that delta between our origin specifications and what the gasoline actually enters the system creates a quality margin that we blend at.
The second piece is more structural in nature, whereas you move from southern climates to northern climates the RVP of your gasoline goes up, that occurs during the fall and then the reverse occurs in the spring if it goes back down. Every time that gasoline allow RVP steps up that’s a transition date for us and we can blend butane into gasoline. Sometimes that’s up to one or two RVP point. So it’s fairly significant that’s why you see most of our blending occurring in the third and fourth quarter of the year and most of our gasoline sales lagging just a bit will show up in the fourth and first quarter of every year.
We have been doing this for quite a while and we’ve become very proficient at it, we track our margin capture and as of recent we’re in the 85% to 90% capture rate of the opportunity that’s available. We spent a lot of capital over the last few years installing blending systems at the locations we needed. We’re still working on the southeast there is a few locations left in the southeast. But for the most part our capital investment we’re getting to the end of the road on that.
We do however see a significant opportunity to improve the logistics around this and Mike will talk about this in a little bit. We spend a lot of money trucking and piping butane around the country to get it to the right location. We don’t specifically disclose the volume that we blend, but if you look at our total gasoline movements and use 2% you’re going to be pretty close to what our annual number is.
Talking a little bit about the economics for butane blending, the curve at the bottom of the page that’s the blue line is the NYMEX gasoline curve, the red line is the Mont Belvieu butane curve the shaded area is the delta between those or the margin. And you can see in 2011 that really started to blow out as crude prices went up due to all the shale production, gasoline went up with it. The production in the shale areas surplus butane, which drove the price of butane down and serve to spread that margin out. That continued until the last half of 2015 when crude prices crashed, gasoline prices came down with them and that margin was compressed.
Still by historical standards it’s still a nice healthy margin but just not what we saw in 2012, 2013, and 2014. And the way we forecast this again is when we give you a forecast for the year, we’re using NYMEX gasoline and NYMEX Belvieu butane. We deduct from that a basis differential, which just reflects the fact that the product we blend in the mid-continent is not priced the same as the NYMEX curve, there is a basis differential, it averages about a nickel over the year.
And we also have significant logistics and RINs cost associated with our blending. RINs are our obligation under the RFS since we blend gasoline we’re considered a refiner, so we have an RFS obligation. We don’t load gasoline across the rack or any fuel across the rack, so we don’t blend bio-fuels, we have to go out in the open market and buy our RINs. Those have run up in recent years and so that’s a cost that we definitely keep our eye on and take into account when we’re calculating our margins.
So we provided you an example spot margin calculation here on the bottom right. This is done on January pricing, the January RBOB price was $1.09 the spot butane price was $0.49 yielding in gross spot margin of $0.60, we within deduct from that the average basis of $0.05 and our estimated logistics and RINs costs of $0.25 to yield in the net spot margin of $0.30. So if you are blending in January and just selling at spot that’s pretty close to the margin you would have seen on butane.
That’s not exactly, how we manage it, we take advantage of the seasonal pricing for both butane and gasoline to optimize our margin. We hedge all of our purchases such that we carry no commodity risks and let me explain how we do that. We look forward into how, what we’re going to blend by month and we have target sets for each of those months. When the opportunity is available to buy butane and sell gasoline in the forward market to capture that market, to capture the margin we’re targeting then we go ahead and do that. And historically between about right now in the middle of June is your optimum time period for locking in your hedges.
Butane starts to getting kicked out of our gasoline pool, so butane prices tend to go down, you’re ending into the peak driving season, so gasoline prices tend to spike up, so that spread between gasoline and butane moves out. We target 90% of our production in future months and then we buy butane, sell gasoline instantaneously, in some cases we lock the basis differential and we buy our RINs. So we got all the costs associated with that blend and locked in all at one time.
And 2016 for example were 60% hedge through the year meaning for our forecasted production we’ve locked in the margin on the 60% of that. The other 40% will be doing here sometime in the next 60 to 90 days. And then again we only go up to 90%, so 10% of revolving, we’re actually doing in the spot market at the time that’s just to allow for any operational and efficiency, so that we don’t hedge right up to the target.
Based on the hedging so far in 2016 given the guidance we’ve provided, we’re estimating in that market of $0.50 that’s a combination of the higher price hedges that we locked in during 2015 and the current spot margins that we’re seeing in the mid-30s to low-40s since a gallon. So you can see for comparative purposes in 2015, that was $0.75 and in 2014 that was $0.90. As Mike mentioned start our guidance assumes $35 barrel of crude price, which is in the neighborhood of where we’re at today.
Just as you are doing your own calculations and comparing in back to what we show you. Again, the margins aren’t going to exactly track, because of the timing of buying patterns, which occur again throughout the year depending on the product prices. We do pool cost our butane, which generates a little bit different financial market and our financial margin than what you would if you were doing it on a real time basis and then the basis differentials, it’s going to fluctuate depending on when we actually still the gasoline.
And then the last piece, much smaller piece of our commodities businesses or fractionator business. We run three fractionators, one in Des Moines, one in El Paso Texas and one in Odessa Texas. Fractionators take transmix, which transmix is the what you end up with when you batch different products and a pipeline were gasoline and diesel buds together, it mix us together, it’s not a saleable product anymore that’s transmix. And what we do is we take our own transmix and we buy third-party transmix, we run through the fractionators, which is just a distillation column, return them back to the original saleable product, sell those products on the market.
Transmix generally is purchased at anywhere from $0.15 to $0.20 discount to finish products, so we have locked in margin much like our butane blending when we buy transmix, we hedge forward, the sale if we know it’s going to take 60 days to get through our splitters then we’ll have that barrel forward 60 days. So we’ve locked in the margin at no risks. And just in general, depending on the price curve we are dealing with at the time, our fractionators generate between $10 million and $15 million on an average year.
So that’s it for refined products. Again, the key things we like to take away from this that we’re working to leverage our assets to meet the changing needs of the market. We’ve done that through expansion such as Little Rock, we think we’ve got some building opportunities off of our Little Rock pipe, reversal of our lines down in the Texas has been an example of this. We spend a lot of time focused on market share and maintaining that market share evaluating pricing service levels to keep it at the high level that it has been for a number of years.
Storage is a big opportunity for refined products. This year, we don’t specifically talk about it as a project, but we’re build 1.5 million to 2 million barrels of storage in the Midcontinent, it’s in very high demand. Maximizing our blending volumes and the pricing is obviously a key effort for us. And then we see growth in this segment through opportunistic acquisitions such as our plains acquisitions a couple of years ago in the Rockies and in new Mexico the couple of terminals we picked up in the southeast we would see that trend continuing on into the future.
So with that any questions on what we talked about so far?
Q - John Edwards
John Edwards with Credit Suisse. Just look like so the butane blending volumes are expected to be relatively flat in 2016 over 2015 if I heard you correctly is that right?
Well other than - the percentages is staying but our gasoline volumes are going up, so it should be a little higher and if you take 2% of the gasoline in 2015 and 2% of gasoline in 2016 you will be a little higher number.
Okay and just were minus why that the volumes are down 7%?
Because when we saw a drop off in crude prices, corresponding drop off in drilling, Odessa is as big a huge market for us, trucking in Oklahoma the Bakken had a big impact on our Dakota volumes and our Western Minnesota volumes. So we saw that up and down that producing quarter on.
You indicated earlier about the PPIs change would be in the index and then you said that there is a 2% overall rate increase in 2016 when we blended the two sides together there. What would be the rate change July 1 as appose to for the full-year?
It would be that 2% from July 1.
That’s July 1 okay. It sounded as if you were saying the full-year.
Yes and I apologize. We just make the rate changes once a year so on July 1.
I understand that but you report full-year basis. Okay, thanks.
It’s Faisal Khan with Citigroup. Just a question on the butane blending, these are for the quality margin and the gasoline come into are lower quality, but by blending butane into the gasoline that’s actually lowering the value of the gasoline. So just to understand the comment that you are making here.
No we don’t change the merchantability of the product, when we set for origin standards, let’s say you can bring nine pound RVP into the system, a refiner connecting carrier never hits us at nine pound they will hit us at 8.5. For a variety of reasons either a refiner may not have enough tankage to optimize his blend and get it right up to the limit or they are just trying to crunch crude and get it out in the marketplaces quickly as they can so they want to hang on to the gasoline to blend it up to that last limit. So there is a variety of reasons why that happens, but the difference from a value standpoints to the market between 8.5 pound gasoline and 8.75 or nine pound there is no difference, it’s all gasoline. It’s all fungible gasoline.
Okay and the whole discussion that refiners are having on shortage of octane in the market, is there any way for you to participate in that with sort of the things you are doing.
There is, we don’t talk a lot about it but a parallel effort with our butane blending is natural gasoline blending and natural gasoline adds to the octane as a tool. So I mean we run that program similar to the butane, so I’m not sure we are in answer for any kind of octane shortages, but we do take advantage of that octane margin as well.
So RINs, what were your total cost for RINs last year?
Total cost for RINs, Paula do you remember I want to say.
$0.5 to $0.6.
But in terms of total margin?
Yes I was going to say 15 might say in 10 to 15.
$10 million to $15 million.
Okay, thank you.
Hi Elvira Scotto with RBC. You mentioned in butane blending that you can improve the logistics as moving butane. You spend the lot of money to truck the product. What are some of the things that you are doing and what sort of margin enhancement do you think you can get?
You are going to talk about those. I don’t want to steer Mike [Indiscernible] but we truck a lot of all volume around. If you take our total logistics cost that’s in excess of $50 million a year that we spend moving butane around. We’ve got a project right now where we’re adding rail offloading in one of our Colorado terminals, so instead of trucking barrels all the way out there we will be able to rail them and then use the satellite distribution in the local market. and we plan to do that at several points on our system.
So for that project for example, we are going to cut our cost by $0.13 to $0.15 a gallon which will go straight to the bottom line.
[Technical Difficulty] getting into the butane trucking business, because we truck so much of it and we evaluated that and I don’t while anybodies in the trucking business, there is no money to be made that, so we’re not doing that.
Shneur Gershuni with UBS. Two questions. One in terms of your opportunities to enhance margin how much is being done on controllable costs for example, are their opportunities to take advantages of the current marketplace to bring down your cost structure. And then secondly, given the performance of your refined product volumes where you just stood at one down the gasoline went up, if oil prices were to go up significantly. How do you think that volumes will change, would you still be flat with where you are right now in gasoline demand goes down just distillate goes up would there be any types of line
Yes, I’m taking the second question later, we would expect for gasoline demand somewhat tight to fuel efficiency and there is a correlation to outright price, but if crude prices go back up such as it starts to effect gasoline volume that’s going to be much more muted long-term trend. So in the short-term we would see that as a very positive where we get bump in both gasoline - get a bump in diesel prices and gasoline volume, which they high as well and then if crude prices stay high obviously overtime you are going to get some negative impact to the high commodity prices. On the margins, we’re talking about butane blending or just overall operating margins.
Yes, I mean that’s a constant focus for us, it’s not the way we’re organized my area and Rob’s area or revenue driven, we have a whole separate group that looks at cost and that’s a constant focus for them. I don’t know that we’re seeing yet surprisingly enough construction cost drop significantly, we spend a lot of money on hydro testing and smart picking of our lines that budget to remain about the same, but that’s a constant focus for us. I don’t know if you have anything to add on that.
Hi Jeff Birnbaum with Wunderlich. Just a question, you mentioned that the FERC margin FERC tariff indexation you are down about 2% but total tariffs you think going up about 2% from June, starting July 1. So just in these markets that are deemed workably competitive broadly speaking, can you talk a bit about the market dynamics that you see where you think you can essentially raise tariffs rather meaningfully and yet not new loose volume, thank you.
Yes, it’s all over the board, it’s 60% of our markets that double-digit market, so it’s a different answer for every market. Some of those we’ve lagged behind the competition quite honestly a little bit on price, so we’re doing some catch-up in that regard and in some instances, we’re just going to be a price leader and count on our service level and the rest of the market to catch-up to that.
But our view is despite the fact that the index is going negative in PPI, cost aren’t really going down that much, so it’s a very justifiable position for our customers and typically when we raise tariffs. As long as everybody’s price goes up to same customers get less concerned about it than as you pick out a particular customer to raise their price or lower their price. So given the range that we’re talking about, we don’t expected to have a volume impact.
One more question again, Faisel from Citigroup. I guess the law suit or a petition from some of the refiners to change the obligation of the responsibility RIN from the refiner to the blender, would that change your cost structure at all, if that was happen?
It would, if that were to go through we would no longer be an obligated parties. So the $10 million to $15 million a year we spend on RINs that would no longer be a cost we’d have to incur.
Okay. Well thanks everybody. We move on to the next segment before we take a break on our marine storage unit, we have storage facilities roughly 26 million barrels, they are all as the name would indicate located along waterway, three of them along the Texas Louisiana Gulf Coast and then two in the Northeast. Our utilization rates have historically been and continue to be well in excess of 90%, there is extremely strong demand for both storage and marine capabilities. Mike is going to talk a little bit about our marine strategy and show you some data behind the export expectations for refined products, but our services remain greatly in demanded all of these facilities.
It’s not as large as the refined products unit, Magellan marine facility was just under 10% of our total Op margin, our storage profit is not very complicated, it’s storage volume time rate and then we do have some ancillary fees that come into play, but the most of our volume is driven by our storage rate. We do have a small amount of commodities in this unit as we have terminal overages, we’re able to sale those, so there is a small sliver of commodities margin that shows up here. the table shows here, average marine storage utilization, you can see it been pretty constant from 2013 through 2016, you can compare that back to the 26 million barrels that we have, so we’re above 90% in most years.
Just one comment, there is a little bit of drop from 2015 to 2016 that’s because we have more tanks out of service for API inspection and maintenance and we’re holding back some tanks at Galena Park intentionally till we determine exactly how we want to deploy that tankage. So nothing has really changed for us other than the maintenance schedules gone up and you can see that all rolls up to $121 million in Op margin anticipated for 2016.
As I said demand for the storage remain strong, what effects us year-to-year is just the timing of our API inspections, tanks have to be inspected on a regular intervals, so we have schedule of all of our tanks across the country and those come off routinely and we stop the revenue billing while that tank is out of service. In 2016 that number is unusually high at 5% which probably has to do with when the tanks were originally put in service we just so happened to have a large volume of tankage that is due to inspection in 2016.
Again, we continue to see strong demand, there is only about 2% of our storage that’s un-leased and as I mentioned at Galena Park some of that is intentional. So we provided you some bar charts here that slice that data a couple of different ways on utilization, shows you the tankage under repair is the yellow bar there on the right and then the un-leased is the blue sliver there at the very top. So you can it, it’s pretty small in comparison to our total tankage.
As I mentioned 85% of this revenues is pretty much guaranteed through the contract, customers pay the storage fee whether the thank sit empty or they turn it several times. There are additional fees that depend on usage, throughput fee obviously is charged as well as some miscellaneous fees like heating and mixing and degassing and those are all usage-based fees. The throughput and the miscellaneous add up to about 15% of our total revenue and that’s pretty constant year-to-year, our customer usage of their tank doesn’t change a whole lot.
Our contracts do include a 2% to 3% escalation, it’s hardwired into the contract and so you can see our contracts schedule there, our contract average monthly rate there at the bottom has gone up from 2013 to 2016. We would expect to continue to see that at least at the 2% to 3% level and maybe a little higher as contract roll off and we’re able to re-lease them at more current market rates, we have some older contracts at lower rate. Right now, our average rate across all five of our terminals is about $0.55 a barrel per a month.
Talk a little bit about the individual terminals real quick, Galena Park is our largest facility at 14 million barrels. We handle a full slate of refined products in blend stock, you have noticed from some of our discussions and media releases that we have added cruel oil capability at Galena Park and Mike is going to talk about that a little bit more in his presentation. We do have room to construct another 1.6 million barrels of storage at Galena Park and that project is under development as we speak. Our connectivity at Galena Park is exceptional. I think we’re connected to all but one or two refiners in the Gulf Coast. We’re connected to all of the outbound pipelines as well as our own marine facilities, rail and truck.
We do have expansion plans for Galena, you have seen our announcement that we’re adding a fixed spot at dock and that we’ve added crude oil capabilities, we’re connecting Galena Park into the distribution system and converting a couple of large tanks to crude oil service. So again, Mike is going to touch on more specifics on this, but that’s an exciting development for Galena Park.
Corpus Christi we have 2 million barrels of refined products, tankage refined products covers the traditional products as well as refinery feedstocks and petchem feedstocks. We have another 2 million barrels of tankage that shows up in the crude financial, this is a facility we split between the two groups. We have access to all the three of the local Corpus refineries. The petchem plant we have inbound and outbound water. We have a room to build an additional 2 million barrels of tankage on the legacy side and then we’ve recently purchased another site nearby in Corpus Christi that we plan to develop. Mike and Rob are going to talk about that development as well.
I won’t go through these other three facilities, they are much smaller than Galena Park and Corpus, but nonetheless they are still above 90% utilization one is Marrero, Louisiana, in Louisiana and then our other two were in the Northeast Wilmington, Delaware and New Haven, Connecticut. Again, long-term leases at those facilities in very high utilization. I will note that at Wilmington we’ve recently add approved as a product slate there, so we have proved refined products and heavy oils at Wilmington.
The pie chart breaks down the 2015 by revenue group, you can see as you would expect that Galena Park is a little over half of our revenue for the marine section. The other four terminals split the remaining 50% pretty evenly. In terms of our contracts, we as I mentioned with the utilization we have, we have a continual role on our contracts this bar chart at the bottom shows you the maturities schedule, we have about 20% to 25% coming due in 2016.
Many of those have already been re-leased or were in the process of negotiating the re-lease, we have no concerns that those will all be rolled at market rates as well as the 28% or so that’s coming off in 2017 and then of course it drops thereafter. But as we renew contracts some on shorter terms as we get closer to those years I’m sure that number will go up a little bit. But the average remaining life on our contracts is about three-years.
So again focus areas for the marine is that we see a demand for both storage and export capabilities and we’re working hard to satisfy that demand, the expansions at Galena dock and some of the other things Mike is going to talk about is where we’re headed with that. We always strive to maximize our utilization and keep our pricing current with market as contracts roll off. We’re very well connected, but we still have a few spots we need to hit on connectivity and we’ve got projects underway to do that.
So with that, I know that was a lot shorter any questions on the marine area?
Thanks. So I wondering if you can just add a little bit more color explanation whatever words you want to use regarding about the length of the contracts on the marine turnovers. I mean I guess you have to presume that you had flat prices in the market for five-years until the entire portfolio catch-up to market. So I’m just curious what the current thinking is about are you going out three-years, going out five-years. How are you playing that? Because other than a flat market price, you are always playing catch-up, which means you have future value in the pocket, but it can be five-years away, or three-years away, or one-year away. Just curious how you play that?
Right yes, it’s a balancing act between optimizing price - I mean we could go all one-year terms at market rate and stay caught up with that we don’t think that’s a good strategy. So we kind of target our portfolio to have a mix of rates in there and it also depends on the customer type. Some of our bigger more credit worthy parties that we know are going to be there for 15-years we’re more comfortable doing a longer term lease with than a shorter guy, less stable guy. Plus we do build in the escalators of 2% or 3%, so we’re not just sitting flat during the entire term of that contract, but it’s a mix and a balance between securing revenue and keeping current with that rising market.
Maybe just a quick follow on to that. So if I’m looking at your contract renewals schedule, here it looks like about 50% of your - roughly 50% of the capacity could potentially go from you cited around $0.55 to roughly about $0.65 per barrel at the mid- point. Is that really more expectation?
Yes, what I have to check on that is to see - I mean we gave a range because it really depends on where the storage is located and which tanks are coming off. So I would have to get back to you and look at the exact tankage. But in general, yes we ought to follow that trend. Definitely on the Gulf Coast where you are seeing $0.70 market rates we would bump rates up there, if some of that coming off happens to be a tank in Marrero then you might not be able to be as aggressive on that. So it really depends on the mix of tanks.
And then just for comparative purposes, you mentioned 5% of the storage is going to be impacted by inspections and maintenance. What was that number in 2015?
Do you know Paula, I don’t.
It was closer to 2% during 2015.
Which I would think 2% to 3% is a more average number, 5% is quite a bit higher than we normally see.
Just following with the last question on the rate, so on the contracts that are rolling in the next two years, are those generally rolling off at the low end of the rate structure would you say below the 55 so that’s opportunistically could roll up significantly. I’m just trying to figure out that mix. And my other question is…
Yes, I don’t have the exact answer to that I don’t know Mark if you know, we probably can get back to you on exactly what that contract role is. I mean that’s baked into our 2016 guidance and of course we haven’t provided it for 2017, but we can get back to you with a number on that.
Okay and just I’m wondering what percentage just as a routine do you lease for one-year or less, and you are saying the average life is three years. I mean is this some that’s just routinely only one or two-years and you have another set of contracts that’s routinely four or five, or maybe talk about that?
Most of our contracts are longer than - I mean I think the three-years probably is a pretty good average. We do have some that has seven or eight years on it. We have a few that have a year, but a year is not the norm, most of them are in that three to five-year range.
Shneur Gershuni with UBS. So just wanted to ask a bigger picture question. You sort of talked about incremental opportunities to build the storage on the marine side and it would appear that you are looking at it more from a perspective that we have a change, we can now export oil and so forth. How do you balance that between the potential that it’s a zero some gain and for exporting oil than we export less refined products. When you sort of think about it globally, is there a risk that you build too much storage, are you better off potentially repurposing some refined product storage and I do realize it’s high storage utilization right now. But how do you balance that and think about that for the longer term that you don’t end up three-years down the road with too much capacity?
Yes. Actually we see opportunities in both. I mean if you look at some of the fundamentals behind the refined products on the Gulf Coast your export capacity is fixed. Demand is not increasing, refinery runs are strong particularly with lower crude. So, there is a significant increase in export expectations for refined products. They basically have to go out for water there is no whether outlook for those. The fundamentals behind refined products exports are much more identifiable than say for crude. And I know Mike and Robb are going to talk about that.
When I talk about crude at Galena Park that’s not going to be our base strategy for Galena Park, one, the asset does not lend itself very well from a draft standpoint, to crude you need a deeper draft to really have big crude volumes. And two if you look at our rates -- refined product rates are 20% higher than crude rates. So Galena Park it’s going to remain crude and that’s where our focus is and we are looking at other facilities on the Gulf Coast that fit the refine products footprint. And we also mind for not to over build whether it’s in the mid count into the Gulf Coast which is why we don’t build a lot of tankage, it’s usually contracted for length of term associated with that.
Unidentified Company Representative
Talking about a lot more later after the break, but the short answer to that is, we don’t think it’s a zero sum gain. And I’ll go through the reasons for that, when we talk about the projects we are working but I think you started the question was it a zero sum gain and I don’t know we necessarily agree with that, if that’s true. So I’ll talk about that more later.
Unidentified Company Representative
This is Robb Barnes, he is my counterpart on crude side and manages the commercial side of the crude business. So I’ll hand it over to Robb.
Thank you. Hello everyone, it’s great to be here. As we stated earlier I have -- our team has commercial responsibility for the crude oil group. We focus on two main areas preservation, our existing revenue stream on our assets today, then we are also responsible for expansion of growth projects to add to our crude oil portfolio. So with those two things, I know Jeff got you all exited that there is going to be break before I came up here, but we can hold that a little bit. After my presentation we will have a break and then Mike is going to come back up and he is going talk in detail around a lot of our growth and expansion projects on the crude oil side as well as in Jeff’s area on the refined and the ring terminals.
So on an overall basis from our crude oil group, it’s kind of indicated here on this map. We have a large presents and our assets are focus in two states that produce a lot of crude oil Texas and Oklahoma. We have roughly 1,600 miles of active crude oil pipelines, the majority of those are supported -- the majority of the capacity in those pipeline it supported by long term take or pay contracts. We also have 22 million barrels of storage of that, 14 million barrels is available for leased storage. The remainder of that storage is utilized as operational storage. And so to just kind of give you a feel of where some of our main assets are in relation to other assets, our Longhorn pipeline originates in Crane and extents down to the Huston market. Our BridgeTex pipeline originating in Colorado City and extents down to the Huston market as well. Both of those pipelines originating the Permian Basin right below them in South West Taxes is our Double Eagle pipeline and that originates and takes barrels out of the Eagle Fort Basin.
Moving north up into Cushing, we have a large storage presence up in Cushing. The red pipelines are Magellan lines that are in or around the Cushing areas itself. And they deliver barrels in to the Cushing market and then the blue pipeline, Mike is going to talk about in great detail as our Saddlehorn pipeline which is under construction right now and that originates up in the DJ Basin and brings barrels down into the Cushing market.
So in 2015, the crude oil segment provided roughly 30% of the operating margin for Magellan, the majority of that was driven by take or pay contracts both on the pipeline side on the tank side of our business. And looking at the chart below here, you can see that there is generally an uptick all of the line items from ‘13 to ‘14 that was driven by the startup of our longhorn pipeline. That started up at the end of 2013.
And I’ll highlight here the earnings of non-controlled entities, what that line item is, is that is our joint venture pipeline projects, BridgeTex, Double Eagle, Saddlehorn will fall into that are OCH [ph] pipeline fell into that and so those revenue stream, those volumes don’t show up in any of the information that I am presenting. They show up on that line item, so the information I’ll be providing is assets that Magellan owns and operates without -- not under a JV partnership.
So kind of highlight in a couple key items here in the 2016 guidance section. The volume shift went down slightly in ‘16 or we anticipate it to go down slightly and ‘16 to ‘15 that’s just do to anomaly prior to BridgeTex being complete where we had all of the destinations connected up to that pipeline system down on the Huston market. Barrels would move down BridgeTex and then they would jump off at our East Houston facility and then they would complete and we would make the deliveries on the Magellan distributions system. That’s not going to occur in ‘16, because we have completed all of that construction, so it just anomaly, volumes are generally going to stay flat.
Transportation revenue per barrel increases slightly, that’s driven by the rate increase in our Longhorn pipeline. And then the average crude oil storage utilized is increased in our ‘16 guidance and that’s driven by additional storage that we’re adding in our East Houston facility.
So how does the crude segment make us money? Roughly 60% of our revenue is generated from our pipeline tariff revenue. Long Horn is a big part of that and I just again reminder BridgeTex is not included in that. And that revenue stream is highlighted in the pie chart below the green section and the red section Longhorn obviously being a big portion of that pipeline tariff revenue. The next largest segment contributing roughly 20% of the crude oil profitability our revenue is our lease storage program. And I’ll talk about that individually here and kind of walk you through the different segments of that, but that’s a big contributor to our revenue stream. And then the lower 25, the lower 20% is highlighted with those four different categories. The largest of those being pipeline capacity leases.
What that is and that’s grown since our acquisition of the BridgeTex assets down in the Houston market. And so our original partner on our BridgeTex pipeline was Oxy. Oxy sold their ownership interest to Plain [ph] during that transaction we negotiated Magellan acquiring the storage and then the roughly 40 miles of pipe that kind of ran right next to our current distribution system. We negotiated that we would buy that and then we turned around and leased capacity in that system, 300,000 barrels a day of capacity in that system back to Bridge Tex. And so that shows up in that pipeline capacity lease segment there.
Our Longhorn pipeline -- so what I’ll do is, I’ll kind of walk through our various pipeline segments and then I’ll shift over to our lease storage segments and the first of those is our Longhorn pipeline. You’re going to see by the numbers here Longhorn pipeline is a very important asset to Magellan’s portfolio. Our Longhorn pipeline is fully leased out meaning we have contracts that fill up all the capacity in that pipeline system. There’s roughly 275,000 barrels a day of capacity. That capacity number is based on a 100% utilization. Our pipeline systems and as you guys know pipeline systems don’t operate at a 100% utilization all the time. There’s maintenance work, both planned and unplanned and other disruptions in a pipeline system so, Longhorn operates at roughly a 94% operating efficiency which generates day in and day out while moving, physically moving 260,000 barrels a day of product.
In ‘15 we added a new origin point, we called it our Barnhart origin station. And that was driven by customer request. So what our customers were doing is they were gathering up crude oil in the Barnhart area which is an area that’s starting to produce a lot more crude oil. So they were gathering the crude oil up putting it on trucks, trucking it back to Crane and then injecting it into our pipeline system and so through conversations with them we spent some capital. Created a new origin point at Barnhart and they pay us an equivalent fee that they were paying to truck it back there to offset the capital cost to construct that origin point and it just makes it easier for those guys to get barrels into our system. Again those aren’t incremental barrels we were full, those are the same barrels, it’s just an easier way on a short term basis and then on a long term basis for barrels to flow into Longhorn.
Volume and rates on Longhorn as I said earlier our Longhorn pipeline is fully committed for the volumes in ‘15 were based on those commitments, volume in ‘16 are based on those commitments and you can see on the graph below that ‘15 and ‘16 are relatively flat at that 260,000 barrel a day volume. 10% of the capacity on a regulated pipeline needs to stay open for spot shipments and so if those, if that capacity is not taken on a monthly basis during the nomination process. Contractually we have the ability to allocate that space back to our committed shippers. And that’s what we’ve been doing, doing with the market conditions that are out there today. It doesn’t make sense for spot barrels to move from the Permian down to Houston based on the margins and the spreads that are out there. And so we haven’t been seeing any spot movements. We don’t anticipate and there aren’t any in our 2016 guidance.
But with our ability to allocate that space back to our committed shippers, what is in our guidance numbers is that 10% of space gets filled up with the $2.20 average committed tariff rate rather than the $4 tariff rate. We expect rates to hold flat in ‘16 based on the negative FERC adjustment that Jeff talked about. And if you just look at the average meaning contract life on our Longhorn practice it is approximately three years. So there’s still a lot of life, there’s still a lot of committed in volumes on our Longhorn pipeline for a term of three years.
Looking down into Houston, so Houston is a very important market for the crude oil industry. There’s a lot of refining capacity in Houston. There’s eight refineries in the Houston Texas City area with over 2 million barrels of daily refining capacity that needs to be met by crude oil coming into that market. We have the most comprehensive, most well connected distribution system in the Houston market today. We are connected to all eight refineries. We’ve -- both in Houston and Texas City we’re also connected to all the third party terminals and then we’re making improvements as well that I’ll touch on here in a little bit that just improve on that, on the ability of our distribution systems to meet all the needs of our customers.
We can access barrels from all the major basins. So as I mentioned Longhorn barrels, BridgeTex barrels coming from the Permian Basin. We receive barrels from pipelines coming in from the Eagle Ford Basin, we can barrels from the Bakken Basin up in North Dakota, those barrels kind of go through Cushing, we receive barrels in from Cushing. So we can accept and touch all barrels coming in from the major basins within the Midcontinent.
And as I mentioned, we continue -- will in addition the size just being able to delivering the Houston market, we have a connection at our East Houston terminal that can may deliveries into Shell Ho-Ho pipeline. Ho-Ho pipeline runs start of our East Houston terminal and our East Houston terminal was showing up in the upper left hand corner here with the green and yellow and red tanks. But the Ho-Ho pipeline runs over to Netherlands St. James area, capacity on that pipeline 250,000 barrels a day and we feed a lot of barrels in there. Shippers want the flexibility to be able to delivery into the Houston market, to refiners there, take it out on the water or to take it over the St. James refining complex.
But while it’s a great system today, we’re improving on that and one of the highlights and Mike is going to touch on it in greater detail, so I’ll just kind of mention it, it is the large longer yellow line at the top of the screen. We’ve negotiated and have formed joint venture which TransCanada. So TransCanada has a pipeline that comes out of Canada goes into Cushing and then they constructed a pipeline from Cushing to Netherland today and then they’re building a connection into Houston and that’s their market link pipeline.
And so their shippers on their pipeline system have asked for the ability to take barrels that they move down on market link and deliver them into our distribution system. So we formed the joint venture with TransCanada to construct the pipeline that allows them to do that. The smaller yellow line and map here is the Galena Park connection that Jeff talk about. What that is a direction from our distribution system into our Galena Park facility, we’re converting a billion barrels of storage at Galena Park to handle the refine products and this is going to allow crude barrels to go out across the dock.
That meets the needs of, a lot of our crude shippers, but not all of them in the restriction at Galena Park is it has 40 foot raft, which is great for refined products. Crude products tend to move out on an Aframax vessel, which needs 45 foot raft and that’s part of our joint venture that reform that LBC here at the bottom of the page. So the Galena Park connection is going to be complete here in the next couple of months giving our customers the ability to move barrels out across the water. And then the long-term plan is our joint venture with LBC, which is highlighted by the red pipeline is down here.
And that’s a joint venture that we formed, it’s currently under construction, we’re constructing just 100 million barrels of storage. There is Aframax dock capability there with 45 foot raft this barge capabilities there as well. And we are in the process of finalizing the agreements to allow that terminal to be connected directly into our distribution system. And so moving can flow in an out of that facility and we can expand the tankage there by an incremental 4 million barrel. So it will be a large marine capable facility directly connected to our distribution system that allows imports and exports of barrels of crude oil barrels. And Mike will talk about that more in his presentation.
So volume and rates, maybe the easiest way to look at this is looking at the bar graph in the lower left hand corner where we anticipate our volume to stay flat 16 to 15. The two largest volume pipelines in our crude oil system our Houston distribution system, which is shown in the green and our Longhorn pipeline, which is shown in the yellow, both of them or about moving the same amount of revenue. They both or we’ve anticipate those both being flat 16 to 15. But the difference between those systems is while they’re moving the same amount of volume, it’s highlighted in the pie-chart in the lower right hand corner.
Our Longhorn revenue were significantly greater than the distribution revenue even though the volume certainly the same and that’s attributed to the tariff rate. We collect the large tariff on our Longhorn pipeline to move the volumes from the Permian down the Houston and then those barrels tend to jump on the distribution system which has a smaller tariff even though it’s a same amount of volume.
So again that highlights affect that Longhorns and important pipeline system to our crude oil portfolio. Kind of looking at the bar chart above that similar to what Jeff showed you. The average tariff, you can see the green bars are Longhorn average care roughly that $2.20 tariff rate. When you average that in with our total tariff rates for our entire crude oil segment it drops the average tariff rate to around the dollar, which is highlighted by that red line.
So our BridgeTex pipeline, this is a joint venture with Plains. This pipeline was born and driven by demand from shippers. There was a strong demand for the ability to carry barrels from the Permian down to the Houston market. And as I mentioned our Longhorn pipeline was full, we have completed the open season on that and then made those allocations and there were still demands to move barrels down. And so we receive commitments to support the construction of this pipeline and we undertook at that time.
Capacity on the people is roughly 300,000 barrels a day today, expandable to in excess of 400,000 barrels a day. Eight times EBITDA multiples expected and that’s based on 70% commitment level -- contractual commitment level. I’ll touch on that little bit on the next slide.
Very similar to our Longhorn pipeline were in the process of adding a new origin point on our BridgeTex pipeline that going to take barrels from the Eaglebine Basin which is about 100 miles to north of the Houston market. Today those barrels get trucked down to Houston. Our pipeline ran right through there based on conversations with a shipper who trucks a lot of barrels down, it made sense for them to sign a commitment with us to support the capital. To construct an origin point here, we’ve done that. We are in the process of constructing that and that will be operational mid-2017 that puts more volume on our pipeline and it makes it more efficient for the customer to ship the barrels and get it to the market that he wants to get it to.
Volumes and rates so I touched on the 70% committed level provides that eight times multiple that we expect for our BridgeTex pipeline we actually have 80% of our pipeline under committed contracts. One of those customers hasn’t moved any barrels based on the market today and the credit rating of that customer we’re not sure for going to move barrels on our system. We haven’t factored that into any of our historical forecast it’s not in our guidance so if that customer does end up making shipments it’s upside. And just a little bit history of how that occurred. We were in the process of constructing our BridgeTex pipeline based on the 70% commitment level that we had received. The market indicators were telling us that there was some demand for incremental commitments to secure capacity on the pipeline to get barrels down the Houston. So went out for another open season we did receive this commitment and we brought them in and so that’s how that happen it wasn’t a driver for us either building or not building the pipeline we were already constructing it was just additive to what we already had in hand.
The average committed tariff on BridgeTex pipeline is $2.60 the spot rate is $4 similar to what we have in our Longhorn pipeline system. 2016 guidance we don’t have any spot shipments being moved. So same as Longhorn, we don’t anticipate any spot shipments on Longhorn as well. And the average reaming contract life on our BridgeTex pipeline is nine years. So there is a long term contracts on our BridgeTex pipeline supporting that moving forward. And you can see on the bar chart here that are ‘16 and ‘15 volume are very similar officially our BridgeTex pipeline started up in March of ‘15 some 15 years and the full year there was a really bad ice storm kind of in that area in January which caused us to shut the pipeline down in January of ‘15. So overall 2016 and 2015 and relatively flat due to those normally.
Moving on to our Double Eagle joint venture pipeline this is a joint venture that takes barrels out of the Eagle Ford Basin it’s a joint venture with Kinder Morgan 50-50 joint venture barrels can be put into the Double Eagle pipeline out of the Eagle Ford and they can be moved on to our Corpus Christi facility, at Corpus Christi we can take those barrels then and directly feed them into the refineries down there or we can move those barrels out across the water. In addition the barrel can go into the Double Eagle pipeline and we’ve made a connection to Kinder Morgan’s KMCC pipeline which is shown in the blue there that pipeline runs into the Houston market and so a barrel can be delivered into Houston as well off of our Double Eagle pipeline system.
Compact rim capacity committed contract capacity on the Double Eagle system as provide 70% coverage or expecting EBITDA multiple of roughly six times beginning in 2017 contracts that 70% of committed contracts on the Double Eagle system provides 70% coverage. Expect an
EBITDA multiple of roughly six times beginning in 2017 contracts. That 70% of committed contracts on the Double Eagle system there was a ramp up of [Author ID1: at Fri Apr 1 01:33:00 2016
]our committed shippers and so towards the end of 2017 will be at that 70% level. Average remaining contract life of on Double Eagle is seven years.
Now I’m going to shift in to the storage section of our group and talk about them there is two terminals that really dominate our storage program on the crude side it’s East Houston and Cushing. First of all in East Houston we currently have 3 million barrels of storage available for lease there all of that, 100% of that capacity is leased out. We are in the process of constructing an additional 1.6 million barrels of that a portion of that’s going to be operational storage a portion of that will be leased storage that will be coming online third quarter and fourth quarter here of 2016.
And our East Houston terminal is really becoming increasingly important asset for us obviously it’s connected, Longhorn barrels come in there, BridgeTex barrels come in there, Marketlink will be coming in we can take deliveries out as I mentioned in the Ho-Ho pipeline system. So it just there is a lot of volume moving through that facility with a lot of flexibility around it. Because of that volume that goes through that facility Argus and Platts have -- last year they started posting prices estimates there, which brings transparency to the market so Midland has its pricing point in Argus and Platts it’s Houston now and it’s the only facility in the Houston market that has that has this transparent prices estimate that is very well received by the market. Recently here in the last month to a couple of weeks NYMEX and ICE which is the international form of NYMEX today and both started posting future contracts at our East Houston facility which is going to give a lot of transparency to hedging and various things and that’s done in our East Houston facility which we think is going attract a lot of volume, a lot of business and this is just an extremely positive mark for our Houston terminal.
Looking at our Cushing facility, Cushing is by far the largest lease storage positions that we have in our crude segment. It was roughly 12 million barrels of storage at our three Cushing facilities and those are highlighted by the green rectangles here down and showing on the map, of that 12 million barrels, 10 million barrels is available for lease storage, 2 million barrels is for operational storage, of that 10 million barrels 100% of that is leased down, the average remaining contract life on that storages is 2 years.
Once our Saddlehorn pipeline becomes operational later part of this year, we’re going to take 500,000 barrels of leased storage and we’re going to lease that back to Saddlehorn to provide the storage necessary for operations of that pipeline. So that will be happening at the end of the year. And we’ve recently competed a major connection project that we installed a large diameter pipeline connecting the three of our facilities together for seamless moments for our customers, it’s been very well received, in addition to moving barrels between our facilities, it also allows barrels to be moved into other third party terminals and we can received barrels from other third party terminals and move those barrels on the Cushing marketing so that’s really helped stabilized all the storage rates that we can charge at our facilities, it equalizes them and gives us the ability to maximize the value at all three of our facilities, plus make a lot of movements to other third parties as well.
We do think that Cushing is going to remain a very important asset for us, Cushing has a lot of size to it, as you well aware there, 70 million to 80 million barrels of storage there, lot of volume goes through there, it’s gives traders the ability to park barrels up in that market, such as they can move amount when they feel like -- when they believe that there’s the highest value that they can get to their barrel, because of that there is lot of supply and demand that goes on, there’s lot of blending that occurs at Cushing.
So, you saw the pipeline on the very first Slide, I showed that Magellan has in the area, there is a lot of pipelines in the Cushing area, they bringing a lot of different crude oil, heavy barrels, mid-level barrels, very light [indiscernible] barrels, all flow into Cushing and then they’re blended up, the shippers can do what they want, they can create, the spec that they want to create and that’s all done in that storage up there. And then the cost of leasing storage in Cushing is relatively less than it is on the Gulf Coast, a number of reasons, supply and demand, cost to construct cheaper up there.
And so because of all those things we just thanking the present that we have out there that we believe strongly in our Cushing presence out there and we think it’s going to remain a valuable access for our entity. We think we have a competitive advantage out there as well, just as a reminder, we don’t have a marketing arm, what we do is we move barrels for our customers, we won’t compete with our customers and so because of that we get a lot of business from people who believe in the transparency that we provide, we don’t share information on volumes moved and we’re not dealing with competitors because of all of that we think we have a competitive advantage and we feel strong about Cushing facility.
Storage utilization and rates, actually the first bullet I’d like to touch on, we have a 1 million barrels of crude oil storage at our Corpus Christi facility, we leased that out today. In addition with that we have acquired 100 acres of land right on the water, right to near our facility there and we have the ability to construct an additional 5 million barrels of storage on this property. In addition to that and the key to having that acreage is we have the ability to construct four private docks, that gives the ability for us to provide secured ability for customers, known ability to move barrels out across the water.
A lot of times in the Corpus Christi market which is a little bit different, there is share docks there, we’re multiple terminals tie into the docks, we do that today with these private docks we can go and sign up customers and they know that they will have set amount of capacity on a dock, and that will be reserve for them, we can do that on the public docks. And so because of that there’s been lot of interest, in adding additional storage in utilizing that private dock capacity down there.
So on an overall basis storage we think is going to remain strong, we’re going continue to look at adding storage particularly at our East Houston facility, it’s very well connected as I described and there’s just a lot of interest in additional storage in that market. Looking at bar graph in the low left hand corner with the green line down there from ‘14 to ‘15, there was an increase in storage, in ‘15 to ‘16. In ‘15, that increase storage was mainly attributable to the BridgeTex assets that we acquired down on the Houston market, so required that 40 mile segment of pipe, in addition to that we acquired storage at our East Houston facility, and part of that acquisition, we sat back and looked at how come we efficiently operate the storage that we do have in East Houston, we were able to free up some storage then put it out to the lease storage market and that’s the increased in 2015.
In 2016, the additional storage come in online is the storage at East Houston as well that’s currently under construction. And so if you look at the pie chart and lower right hand there, with the volume of storage at Cushing, you can see Cushing is a predominant revenue generation from a storage perspective for our crude oil segment. But based on what I just touched on ‘15 and ‘16, the red segment there at our East Houston facility is growing and we anticipate that continues to grow.
Looking at the bar chart just above that the blue and yellow one, on average our re-storage rate is approximately $0.50, $0.40 of that is arrived at from the least storage rate itself and then $0.10 is arrived at from throughputs into round that least storage program. So some key focus areas for us moving forward, our long haul pipelines, Longhorn, Bridge Tex what we’re looking to do and are having more conversation around is to take that origination point and allow barrels -- we’re looking to go back into the basin further. So that’s through gathering lines, through joint ventures through acquisitions of new pipelines, construction of pipeline. But we’re looking to go back into the basin deeper, that going to help pull barrels into our long haul pipeline and make it easy for the customers to do that. So that’s a big focus area for us.
In addition, the import and export facilities that we’ve talked about namely at East Houston and Corpus Christi and the just increasing our storage capacity, one think I’d like to highlight that kind of concludes everything. One thing I’d like to highlight is kind of stepping back to that. First bullet item is, there has been some questions around the ability to retain volumes on our long horn pipeline or some of our long horn systems and what happens in the current market that exists today, so I can tell you we have a lot conversations with our long horn shippers and our shippers on our long horn pipelines they like the ability and the ease of getting barrels into our long horn system.
We added the new Bernhard origination point which is easy for those guys to move barrels in. Probably the most important factor is the rate that we have on our long horn pipeline, that $2.20 average committed tariff rate is as good or better than any barrel or any pipeline that moves barrels into the Houston market today both that’s in existence or that’s being talked about being constructed so from a competitive tariff rate we feel very good about that right. And then as I kind of walk through the Houston distribution system where those long horn barrels land, it provides easy ability for shippers to get barrels where they want to go. And with the addition of the marine capabilities that we have that was kind of the last box we needed to check to provide the full capabilities that everyone is looking for and so with all of those factors we feel confident on our ability to retain our volumes on long horn.
Additionally we’re looking to add a commensurate grade on our long horn and BridgeTex Pipeline which gives the customers the ability to maximize whether they want to take that barrel and blend it or move it in or they just want to move that barrel directly to Houston that’s something they’ve been asking for. We’re going to have that in place here shortly. So I just want to kind of touch on that real quick before we jump into questions, which is where we’re now.
So if there is any question out there.
Steve Sherowski, Goldman Sachs. Just on extending pipeline systems deeper into basins to secure volumes, you plan to do that through JVs or new build and are you currently in any discussions with the third parties?
Is that a new pipeline coming out of basins, I missed the beginning of that story, gathering systems. So we’re looking to do with ourselves, if we can take a small diameter gathering line and bring it back into the basin, again it needs to fit the needs of a customer. But if there is already a gathering system in place, we could look to have conversations with the owner of that and form a joint venture or we could go and have somebody else build it if they were to do it if they have a relationship with the shipper who wants to move that barrel. And then we can create a joint tariff that allows that to economically move into our long haul pipelines. And so while we don’t have a set way of doing that we’re looking at all the options that are available to go on the track that barrel into our long haul pipelines and make it easy for the customer. That’s the key, a lot of times they don’t like to negotiate a deal with one pipeline and then it ships over to another pipeline and then it goes into our pipelines. And so if you can make that seamless and easy for them and that we’re attempting to do.
Just a quick follow-up, there was a court filing last week lower the volumes for Tier I and Tier II customers on Saddlehorn, can you just talk a little bit about that, what drove the decrease, what makes you confidence there is not going to be further decreases over the near term or the long term?
Yes, so that was completely based on the undivided joint interest that we entered into with Grand Mesa Pipeline and so Grand Mesa Pipeline was our competing pipeline that was looking to be constructed to be built from the DJ Niobrara Basin down into cushion. So we got together with the NGL folks and they decided to cancel their projects, so they’re no longer constructing their own pipeline and they came into our pipeline and so we have 340,000 barrels a day of capacity. We have 190,000 barrels a day of that capacity for Saddlehorn and they have 150,000 barrels a day of capacity in the pipeline.
So it’s a pipe it’s kind of like two pipes within one pipe and through our contractual arrangements with our shippers Anadarko and Noble they have the ability to have kind of a first call in that expansion space. And so through negotiations with them with them rather than go and construct and build up the pipeline system greater than what was necessary to move -- greater than 340 is maybe the simple way to look at it. We negotiated with those guys so rather than spend a lot of capital. We were able to negotiate with Anadarko and Noble, and provide a reduction on their near-term front end tariff volumes for a portion of it and then we took some of it and just moved it to the back to the year five of their contracts.
So we did it due to contractual obligations with our shippers and we reached an agreement that allowed us to do that in a most economical way. So we’d say the lot of capital rather than expanding the pipeline for space that wasn’t necessary by just providing moving barrels from years one to year five and then for giving us a portion of that volume.
Just I guess as a follow in terms of getting deeper into the base and will your tariffs be similar in terms of take or pay? Would you be willing to take on more volumetric exposure if you do get deeper into the basin? And then if you are gathering volumes or putting additional receipt points in, does it really need to be the same producer customer that also the long haul shipper whether it’s on Houston or on Longhorn. So for start that.
So our preference is to work back and do a take or pay to construct that capital, probability of that is probably low, the dollars again on a relative basis aren’t significant. And so we could do it under take or pay, we could do it under acreage dedication, or we could do it if we feel like we’re going to touch a lot of different shippers and get barrels in. So, we could do it at risk. So all of those options are available to us, our preference is to do it where we have support for it. But if we feel confident we can do it otherwise.
And then your second question on are those the shippers that are moving barrels or the actual committed shippers on our long haul pipeline, some of them are and some of them aren’t. Some of them have arrangements to purchase that barrels or some of them been talking with the shippers they say come here because I can reach an arrangement with one of those committed shippers on your pipeline to get the barrels in there. So, it’s combination of all of those things.
And then on the contractual profile in terms of the credit profile of the shippers on Double Eagle, given potential production out for the Eagle Fort confident till then, so they not that even, the barrels may not necessarily be there?
Yes, on an overall basis for commitments on our pipeline systems, 95% of our shippers in the crude segment are investment grade shippers. And so we’ve publicly announced to the Double Eagle shippers are Talisman Repsol now StatOil [ph] and they are in that classification, they’re investment grade and so we feel confident that those volumes are going to show up, or they’re going to make a deficiency thing, which is essentially a prepayment for a barrel that can be shipped later and they’re doing that.
I have two quick questions, one is, can you just elaborate on why you need so much storage for operational usage, and that’s one. And then two, more philosophically, on the decision tree of not having a marketing company, because you don’t want to compete with your customers versus the thought process of having a marketing company to ensure that your assets are being fully utilized.
So the first question on the amount of operational storage, any time that you are having origin of destination points for pipeline system there is some operational storage that’s necessary to facilitate that business. I think probably the biggest factors, one of the big factors that we have -- so it’s like tank bottoms for example. There is tank bottoms there that is -- there is a floating roof on the tank and you only can take it down so far and so there is this volume of storage at the bottom of the tank that isn’t accessible and that gets factored into that operational storage. But a big part of that difference between the 22 million and the 14 million on that very first page is our contractual arrangement with our large customer in Cushing.
And so as part of that we need to hold some operational storage that allows those guys to facilitate their business model and that was the contractual arrangement that was in place when we acquired that facility and it’s stayed in place through renewal of the contracts. And I forgot your second -- the marketing arm. So we debate that. We talk about that quite a bit internally not so much recently here. But we have that conversation around there is revenue to be generated by having a marketing arm. But we prefer to not do that. We think it sets us apart in the marketplace. We think we get business.
We get some expansion opportunities. We think that relationship with those guys, as a lot of those customers are able to speak with us more freely and that they’re willing to sign longer term contracts with us because we don’t compete with them. They know that we are not going to take any information that we derive through their movements or their transactions. Now I can tell you some of the things that we have looked at is, while it’s not trading at all, it’s buy-sell arrangement, which would potentially help get some volume on our pipeline systems and a simple way to do that is, we would go potentially on a gathering system that customer says, I don’t want to do the hassle of signing contracts and working through all the issues to take this barrel from the Permian and get it down to Houston, what we could look to do is to go in and say we’ll buy that barrel from you say for $2.50 were shifted down will charge you to tariff and sell it back to you for $2.50. And we can do that we have look at doing that, we haven’t done it yet but we have those conversation and that’s something I think that we would entertain as long -- as it made it easier for barrels to come on our pipeline system.
We have time for one more question.
Shneur Gershuni with UBS. Just going back to Steve’s question on Saddlehorn, I guess two questions one with the unfortunate increase in labor availability, is there a chance that the cost related to the project have actually come down and the returns substantially go up?
And then I guess second, we have seen a major pipeline project get delay in different Basin this year after request of the shippers. Is that a potential risk for Saddlehorn or are you too far down the process of this stage to even entertain that type of the discussion?
I miss the second part of that question, I am sorry.
There was a major pipeline that was delayed in the different Basin at the request of shippers, it was negotiated, are you at the stage of this point right that that would be too late even entertain that type of the discussion, or is that still a potential risk that it could be start date could actually move at the request if the shipper’s delay to start day?
Yes, so answering that question first. We are pretty far down the road, that pipeline going to come online here at the end of 2017. And we haven’t had those conversations with those shippers up there as of right now. They have made plans for their barrels to move into our pipeline system. Not to say that those conversations could not happen, but that hasn’t been a part of the discussion to this point and we are moving down the road and that pipeline is, there is a lot of that pipe it’s in the ground today.
And so the first question on the actual cost, we feel very good about the rate or the capital number that we put out there. And not going to -- we feel confident that we will come under that number.
Thank you very much and I’ll be available for questions afterwards and now we got to take a break.
We will take a short and let’s plan to be back by -- it’s almost 11, let’s plan to be back close to 11:10 at this point. Thank you.
Alright, if we can get everyone to get back to the seats, we’re going to get started again.
Alright, well the next section I’m going to go into a little more detail on our growth projects and then I’ll turn it over to Aaron to go through the financial information. But to just kind of start with, if you look at -- and I’m not talking about our $900 million of spending in greater detail. But we’re pretty evenly split on those projects between the five products in crude oil project.
Which is, if you remember from a couple of years ago, we’re much more predominant on crude oil project. We’re more balanced now, if you look at our potential expansion project still slightly skewed towards crude oil, but we’ve got some significant refined products opportunities that I’ll touch on here in a minute. And all of this is still a shift towards crude oil. We are at 70%. Our current operating margin last year was 70% refined products, 30% crude. If you project forward at the completion of everything that’s being built right now, it will probably be closer to 60 to 40 when that’s all done.
So, just going through the projects, Little Rock pipeline, first of all I will talk about this project, we’ve been talking about it couple of years. We expected to start operations hopefully in May. This project was driven by two things, it’s fully supported by commitments that generate just at the committed level by the eight times EBITDA multiple, it was driven by the market being under served; there was a change of services of some pipelines into the market. But in addition to that I’m going to talk about this more globally here in a minute. The Midcontinent refiners connected to our system, Oklahoma refiners, Kansas refiners desperately were looking for new markets and are still looking for new markets for refined products. Little Rock had never had access to refined products supply in the past and now will. And so there is strong support for this project. It’s 200 miles total. This project -- strong support -- it’s interesting, there is a lot of issues with building new infrastructure today. But when you are providing infrastructure that directly supports the state you are building it in, you get a lot of support. So, thanks to Bruce and his team, we were able to get this project done relatively quickly in this environment and on cost.
We’re also talking to a third-party about connecting and extending the service select which we think is likely going to happen here in the near future. That doesn’t require any new pipeline builds. In existing pipeline, we’re going to connect to the served West Memphis to the system. But that’s moving along pretty quickly. Total it’s $200 million project. We just expanded the capacity recently by adding some connections to the existing terminals in the market. They’ve I think seen a trend of what’s happening and expect a majority of the supply into the market to come from this pipeline in the future. And so, we’re going to be connecting to the other terminals in the market and we’re also adding jet fuel capabilities. They are not just for the airport but there is an airport space there; it’s very interested in jet fuel supply from the Midcontinent into Little Rock and we’re also making connection into railroad fueling depot. So there is a lot of upside to this project. As I said, there is commitments for that support eight times EBITDA multiple on this pipe but that’s less than 50% of the capacity of the pipe. We have high expectations in discussions with the customers that we’re going to be moving significantly more in the minimum commitments and the return on this project should be substantially better than that. And again, the timing on that is to complete that in May and start operations in June of this year.
Just talking about the larger trend, I mentioned that refiners in Midcontinent are looking for more options. What’s driving that primarily is the abundance of crude oil, domestic crude oil, the whole shift in domestic inland crude oil being cheaper than crude on the coast, which is a flip from where it was five or six years ago. And so, now you have Midcontinent refiners, Kansas, Oklahoma refiners that are looking to increase the run rate, the utilization rate and in some cases expand the refineries. In order to do that, they need one of two things and maybe both. One of the things they might need is storage. The gasoline demand is low in the winter, high in the summer. They would like to run their refineries in the winter at higher rates and store that gasoline to sell in the summer. That leads to more storage opportunities. Jeff mentioned that we’re building some stores now on our pipeline system, all under long-term contracts but still substantial interest from refiners to add even more storage to be able to really to support them running the refiners at high utilization rates.
But the other thing that they need is new markets. The Midcontinent, probably the group three, sometimes we call it the group, is it kind of a confined market. It’s got limited demand, limited geographies and the embedded refiners have been held hostage to that market for quite some time. They are looking to expand those markets. And we’ve got significant capability to do that for them and in some cases at relatively low capital. The Little Rock project, the arrow to the east is one example of that, the access to new market from that refining base that they’ve never had access to before. And again, if we extend it to West Memphis and even extend it even further, we’ve got an arrow up to the Rockies. Once we bought the Rockies system from Plains and we are now in the process of connecting that to our system, it gives additional new markets for Midcontinent refiners to access. For example, the ability to physically move a barrel from a Midcontinent refiner to Colorado Spring for example, has never existed before. We are going to create that opportunity for them to move physical barrels and supply that market.
And then, movements to the south, movement south from Oklahoma. I mentioned this couple of times, I’ve been with this pipeline system for 30 years and we have really never moved refined products south of Oklahoma into Texas. Well now, it’s happening. We’ve set out the system to reverse, so that we can move -- movements out. It’s happening sporadically. We would expect over time it’s going to continue to grow. And when I say south, we’re moving it down into the Dallas market. And once we get down to the Dallas market, we can move the physical barrels west, in the West Texas and then connections there to point even further west in Arizona or New Mexico.
And so, we have the capability to accommodate the refiners to expand their geographies for physical marketing, without spending a whole lot of capital. And those movements are typically higher tariff movements for us. And so as this trend happens, we would expect our average tariff rates -- recognized tariff rates to increase because we are moving the barrels further. What’s allowing this to happen, and I’m talking about this in a minute is Dallas has historically been a Gulf Coast supply market. The Gulf Coast refiners are becoming more and more accepted to giving them market out and moving the barrels to the export market. And they get better net backs rather than compete with the Midcontinent refiners, bringing the barrels down, especially, seasonally in the winter when that happens right now, the most. So, those trends are continuing. And we would expect that to continue over time as Midcontinent refiners look to expand their capacity and run rate.
One related example, this is a project we just did with Holly. We had 50% interest in Osage pipeline which is crude oil pipeline from Cushing up to Kansas to primarily supply Holly’s refinery. We just sold them half of that pipeline, our half, 50%. And in exchange for that we did a long-term refined products deal with them in El Paso. So, they now own that interest in Osage and we’re constructing connections to Holly Energy Partners pipeline in West Texas, such that all of Holly’s refined products terminalling needs and transshipment needs to Arizona, will now move to our terminal once we complete these modifications.
You’re going to see when we report our earnings, you’re going to see a $27 million non-cash gain in our earnings associated with that swap. The net effect to us, again we didn’t get any cash for that transaction; we’re getting a very long-term market commitment in El Paso associated with that. And it’s going to increase our cash flow about $2 million a year, just on that slot with Holly. So, you will see that gain in the earnings in the next report. It’s going to take us a couple of years to get this done. And so, we’re getting a ratable cash flow payment from Holly that approximates what our Osage earnings were in interim until we get this infrastructure build. And this adds additional opportunities of $2 million, just based on the volume we expect from Holly. We also thinks that this is going to create more storage opportunities on passing, [ph] more blending opportunities because we’re in more gasoline moving to our system.
Butane blending growth projects, Powder Springs, we haven’t talked about that whole lot but that’s a JV that we signed with Colonial about a year ago, where we’re partnering with Colonial to build the butane blending facility in Atlanta. And we’re going to be the operator and manage the operations there but it’s being set up to blend butane into entire Colonial gasoline stream, moving to Atlanta to points beyond that. So there is a substantial opportunity here, even at the current reduced margins versus what they have been the past couple of years, it’s a tremendous return on this project. It’s not a lot of capital, it’s about $20 million of capital or thereabout, but the return on this and the return potential is pretty significant on Powder Springs.
We’re also, as Jeff mentioned, putting in rail facility in Denver. All the butane is trucked to Denver from Midcontinent, very expensive. We’ll be able to reduce our logistics costs there substantially. And we’ve got number of other projects to expand or improve the amount -- the efficiency of blending on our system. Those logistics opportunities, as Jeff mentioned can be pretty material. We’re looking at some additional rail facilities; we’re looking on one Atlanta as for Powder Spring, can be material to significantly lower our logistics cost, on moving our butane around.
Saddlehorn pipeline, Robb touched on lot of this already. So, I’ll go through this rather quickly. Saddlehorn itself is 40% on by Magellan, 40% by Plains, 20% by Anadarko. We are the operator of the system. Our capital portion of this project is $260 million for the line from Platteville to Cushing and for the extension up to Carr. The point, I talk about the commitments here in a second, the extension of the Carr is important, it’s not big on the map but it’s big strategically because that Carr, Plains has assets, pipelines have come down from Guernsey. So, we will -- Saddlehorn will have access to the broader Rockies market for crude oil supply. Southern Wyomng, Powder River basin and through other pipelines coming down from the Bakken barrels.
We don’t have unlimited capacity obviously from those markets but we certainly have what we think is a competitive option to move barrels to Cushing out of those basins for some volumes. And we’ve got some interest from folks up there; they’re interesting in doing that. In addition we’re in current discussions with people in Northern Colorado and Southern Wyoming for additional barrels onto Saddlehorn. And it doesn’t take very many incremental barrels on Saddlehorn to improve the returns pretty significantly because of the high tariff on Saddlehorn to get the barrels to Cushing. So that’s a pretty significant extension there. And we’re the only ones -- I’d say the Saddlehorn’s the only one that has access to that. We’ll talk about the joint interest with NGL here in a minute, they don’t have access to the barrels coming out of Carr, to Saddlehorn, it does.
We did the consolidation; Robb mentioned this. If you have questions later, I’ll talk about some of the history behind that. But we did consolidate 340,000 barrels of total capacity on this pipe, Saddlehorn has 190, Grand Mesa has 150. The beauty of this arrangement really the only way it was going work for us is that we kept our contract separate that’s the advantage of the joint interest by joint interest. So, we’re not exposed to any credit risk on their shippers. They’re not participating in any of the benefit from our contracts. So, we need to keep our contract; it’s really like the pipe within a pipe. We keep our revenue stream separate and we share the operating cost and we share the capital cost.
So, given the situation of the DJ Basin is likely to be overbilled for some period of time, this was a good consolidation. We talked a little bit about the concessions we had to make for Anadarko and Noble which lowered our throughput slightly, I think the number was 10,000 barrels a day for one year. But the tradeoff we got for that by being able to do this is we’ve reduced our capital by $100 million and we’ve reduced our operating expense indefinitely by a significant amount by putting this together.
Back to the timing, there was a question on the timing. This project is significantly advanced. In fact we’re anticipating starting up the plant of the Cushing section here in six months or so. So, we’re well underway with this project.
And again, I think this is a project that maybe to some extent would surprise ourselves; how quickly we’ve got through the permitting process and the construction process, but is moving along very quickly and at this point, probably under budget. The Carr extension is going to be -- we started that little later, so that wont’ be running until late in 2016, right at the end of the year. We’ve talked about the expected results. We have five-year contracts on this from Anadarko and Noble. We haven’t been talking much about the volumes on it but I think it was pointed out that Plains put the volumes in one of their presentations. So, I guess we can talk about it too. But the volumes that we had, committed volumes started about 40,000 barrels a day and ramped up to 80,000 barrels a day. That average is out for about nine times EBITDA multiple on our $260 million if we don’t get another barrel through there. We are optimistic we’re going to get incremental barrels through our space in Saddlehorn. But those are metrics behind what supported the investment.
We have nothing in this year’s guidance with regards to cash flow from Saddlehorn because we recognize that we get a distribution and we’re not projecting -- even though we’re going to start up September, we’re not expecting to get a distribution out of the JV until early next year. And so, we don’t have anything in our DCF guidance this year from Saddlehorn.
The splitter, I’ll go through this quickly; we’ve talked about it a lot. And maybe without going through this slide in great detail, probably what’s most important to many of you is whether or not Trafigura is concerned about this investment or not. The answer is every indication we’re getting from them is that they’re very still happy with this investment. They have got, and you can see the products that come off with this facility. Their needs to fill their trade book, I think fit with this at the rates that we have off of them in the contract. And so, we are still proceeding full stream heavy and not -- we have had no discussion with them or nothing requested to consider delaying this or renegotiating this. So, this project is fully on track. It’s a $270 million project.
The contracts -- we’ve talked about contracts being frontend loaded on the fee so that we would have certainty of not only return of our capital but return on our capital within the initial term of the contract. And in exchange for that, if they extend and then the fee drops off substantially, if we average those two together, it’s a six times multiple on the project. So it’s very strong project.
Often times we get asked, what happens if it is terminated after the end of the initial term. You can see there that only 35% of the spending on this on the splitter itself. The remainder of the spending is on additional storage and dock capacity that we can use for other services, if the splitter itself is not operating post-contract period.
And there is the milestone there. We’re on track for having construction complete late in the second quarter and then expect it to have operational in the fourth quarter of this year before the end of the year.
Talking about marine strategy, this slide is pretty compelling when you look at what it’s actually saying. But this is a projection of export refined products, Gulf Coast exports over the next few years and there’s a dramatic increase in this number. This gets back to the comment I was -- we don’t think this is a zero-sum game. Why is this happening? Why is this -- look like this? So there is a couple of things happening. I think first of all, there is still even though we think that the data maybe a little bit bullish, the expectation is demand for refined products, domestic demand for refined products is on a slow on and gradual decline. That’s one contributor to this. The other contributor to this is just addition to what -- or extension to what I was talking about earlier, Midcon refiners are looking to run at higher rates and higher utilizations. And there is a number of refining centers that are looking to do that to access the export markets. The inland refiners obviously are looking to access the export markets. Even though I will say we’ve had some of them come to us and ask how we can get a barrel from Oklahoma to Houston, which is a little hard for us to do in our system. But, this just shows that there is a strong desire and economic push by these refiners to increase exports of refined products.
To the tune of up to 1 million barrels a day of incremental projected refined products exports, those facilities to handle that growth don’t exist today. So, when we talk about focusing on expanding our marine strategy, it’s not just crude oil, it’s also refined products and refined products is a critical and significant piece of that strategy. So, the things we’re doing there, first and foremost, we’re adding the dock at Galena Park. So, this $110 million [ph] project we’re adding in the ship dock and very well received by our customers at Galena Park. We’ve talked about the rates we’re collecting at Galena Park, and I know there are lot of questions as to are we going to just jump those up the market rate when we renew the contract.
One thing we didn’t mention is, one of the things limiting Galena Park is that it is constrained on dock capacity. And so, we have been hindered historically and not being able to get market rates because our docks are congested. This will solve the problem for us. And so, our expectation is that we’ll be able to increase our rates quite a bit once the stock is operational. And again, our customers are fully behind that to increase access to the water out of Galena Park. This won’t be done until late 2018 just as a long lead time project for permitting and doing any work down there on the ship channel actually on the water, it takes quite a bit of time.
And we’re also -- we mentioned connecting our crude oil system into this. In fact, we’re doing that on short order. So, it’s going to be ready late this year. That’s not a long-term solution for a crude oil export facility, it’s more of a stock gap. It will put us in a position where we can offer the service on a limited basis right now, as we develop a broader crude oil marine strategy, which I’ll talk about in a second. Bob also talked about our joint venture with TransCanada, so I won’t go into that a whole lot more. But I can tell you that this is a very strategic connection. And access to Cushing barrels, they come down, want to access our distribution system are important.
As you know, there is only two lines that run from Cushing to Houston, one is the Seaway System and the other is TransCanada. It’s unlikely the Seaway System wants to use our distribution system, given its ownership. But TransCanada has only two options, once they get to their shippers, I should say only have two options when they get to Houston to either use our system or use the enterprise system. The enterprise on Seaway, it’s unlikely they’re going to be real receptive to the competing pipe from Cushing. So, we’re perfect connection for TransCanada to provide open access distribution for barrels that they want to move down or their shippers want to move down into the market from Cushing.
Our joint venture with the LBC as we call Seabrook Logistics, we announced that last year. The initial phase of that that we announced was of limited scope. It’s a very good project. We’re building 700,000 barrels storage there. We’re building a pipeline out of that facility to connect to a refiner’s pipeline and it’s being designed right now as an import facility under a long-term contract with a Houston area refiner to support that. But it’s the platform for a much larger expansion as an export facility. And the potential there is up to 4 million barrels of storage, an Aframax dock and then connections to our distribution system, which once all of that’s complete, we would have a very significant marine crude oil export capability that’s outside the ship channel. This facility is south of the ship channels, so you avoid some of the congestion in the ship channel. And we’re making significant progress on this project. Hopefully, we’ll have something to announce on it here in the next few months. But, this is the crude oil component of our marine strategy.
And then just to summarize the line items, what builds up to that $900 million. You can see the top four projects are really the big drivers are Saddlehorn and Little Rock, Glena Park dock and Corpus Christi splitter. But then we got a number of other projects that build up to that. Various tankage projects, various pipeline projects. We got Seabrook in there. Robb talked about the Eaglebine origin and I won’t go through all of those. But I’ll say and I’m going to talk more about our backlog after Aaron speaks, but those kind of the projects those $20 million and $25 million projects, we got a long list of those that are available to us given the breadth and scope of our system. And so in those times the projects, even though they’re small in capital, they’re usually pretty high return. And you can see -- I mean if you add those up in total, it’s a pretty significant amount of capital. So, those kinds of projects in addition to the large scale ones to get the headline, are significant portion of our project backlog. And there is as many of them there that in that backlog or more than we have on this list. But, I’ll talk about the backlog here in a minute.
And so, I’ll take question real quick and then I’ll let Aaron talk and then I’ll back up here to finish though broader questions, you can say for the very end, maybe more efficient.
Hi Mike, real quick on Galena Park, just trying to get understanding. When the dock is operational, you figure you are going to get the 9 times multiple of the construction cost because you will be able to raise the price of the current contracts.
That’s part of it. And then we are going to have loading fees also but that’s part of it.
Okay. I guess the question is how long of a period for these contracts to roll over post 2018, the dock in expanded and operational or you are discussing now with these customers about extending their contracts that they currently have for the post 2018 period at the higher rates?
Do you want to answer that, Mark. Mark runs our marine terminals. I’ll let him answer that question.
Sure. It’s a combination of both, really. We are in the process right now of negotiating new contracts with customers that are aware of this and they are willing to sign longer term higher P contracts at this time. But there are contracts obviously coming off after the dock comes into which we will be renegotiating at that point. That’s all been factored into the return. We’ve kind of model that into our cash flow expectations on a return calculation; it’s one the blow offs and one that reflects higher fees.
Alright. Well, again, I said I’ll be back up here to close and you can ask broader questions. So, I turn it over to Aaron now to go through the financials.
Thanks Mike. Can you guys hear me okay. It’s harder to hear up here I am finding than it is when I am sitting out there. We can make this real simple. I think Mike put my section of the presentation between gross and sort of sandwiched me in here with this potential growth. And also right before lunch because we could make this real simple, I could just get up here and say from the finance perspective, everything is just fine. We are in a good shape. And we plan to keep it that way. But he wouldn’t let me get off the hooks sort of that easily. So, I am going to spend a few minutes, I hope to convey to you sort of our philosophy about the finance policy as much as anything and then also demonstrate how that philosophy is sort of permeates to how we run our business and how it relates because as we are making financial policy, I think it’s important for you guys to understand how we are thinking about thing, as much as the actual numbers themselves.
So, at the end of the day, what I hope you pull away from this section and what I hope you learn this morning is that our businesses are doing pretty well, they are healthy, they’re growing, they are very stable and that’s what everything sort of starts. And from there, we have got a strong balance sheet. We continue to have a reasonable access to capital. And when you add all that together, it means even today, we still have a very competitive cost to capital that allows us to make investments to create value for you. So, it all interrelates.
I am not going to spend a lot of time on our strong financial performance. We spent a lot of time on that on our call. I would highlight just a couple of things. So, in 2015, from a thematic standpoint, our businesses all performed quite well. We had our commodities business, which on a relative basis still performed pretty well but it was down from the record year in 2014. So that caused our refined product segment to look like from an operating margin perspective that it was not growing. But when you exclude that commodity piece, the underlying business is very healthy as is the underlying business of our crude oil segment, the underlying business of our marine storage.
So, in ‘16, we’ve given guidance $900 million of DCF and that we are going to grow distribution by at least 10% or by 10%. 2017, we expect to grow distributions at least 8%. And we plan to do that while still maintaining 1.2 times coverage ratio. And we think it’s that combination that’s very valuable in today’s market and very important to how we are approaching financial policies going forward.
So, we have very stable businesses but of late, the question has been how stable are our customers. The contracts that we’ve entered, can we rely on them to provide the returns that we’re expecting. This chart is really a summary of what we talked about in the first quarter call. If you look at the chart and you combine the red segment and the blue segment, our crude oil and marine segment, those are the segments that are most driven by contract. Those are the segments that we must rely on the performance of our customers in order to earn our return. If you combine those two segments, 75% of the revenue in 2015 for those two segments combined are from investment grade counterparties.
Now, let’s break out the crude oil piece and talk about that specifically for just a moment. If you look at -- which is dominated by our long-haul pipeline which was built recently and as a result we have many long dated contracts still remaining on those pipeline. 95% of the revenue in 2015 for that segment on the pipeline commitment is with investment grade counterparties and in fact, is heavily biased towards the higher end of investment grade BBB+. So, when you look at the few segments in our business that are most driven by contracts and therefore have a most counterparty risk, we’re in very good shape with very few concerns.
Now let’s talk about the refined product piece of the equation a little bit. And it’s really the refined products space, and we get a lot of questions about what’s your average credit rating, a lot of emphasis on what is the credit rating of your customers. But it’s really this segment that introduces in our mind a little bit of complexity in terms of how we talk about credit. Because it’s not really a contract driven business, it’s a demand driven business. So, whatever the demand is within our segment for the most part of the pipeline, if a particular customer does not perform, the demand remaining, it’s there; it didn’t evaporate. As long as people are still driving their trucks and their SUVs, the demand is there and we’re in a position to serve that demand. So, if a particular customer doesn’t perform, in all likelihood, another customer simply steps in.
So, the credit rating of a particular customer in that segment is really irrelevant when you look at how the segment fundamentally operates. With that said, most of our customers in the segment of the refiners connected to the system are doing quite well and quite healthy. So, we don’t have any particular credit concern. But I think understanding that fundamental part of the business, it is important to understanding for us and for you as we look at our credit exposure.
Now, let’s talk about our commodity exposure a little bit. I just spent a lot of time talking about butane blending. I’m not going to spend a ton of time on this slide, I just wanted to highlight a couple of things. So, when you look at our business, we have our group of commodity related businesses. It’s going to be our butane blending, fractionators, our inland terminals and ring terminals over in short. Put all that together, that’s our commodities related business. But within our segments and our pipeline, related to our pipeline operations, we also generate product gains where you see tender deduction. There’s also some commodity exposures there as well. So, those are the three areas, commodity related activity, the majority of which is butane blending and then our product gains and losses within the segment and so.
Back at the guidance for this year, we provided a sensitivity of every $1 change in crude oil prices, we expected a $3 million change in distributable cash flow. As a general rule, that sensitivity is still valid today. But I do want to highlight that it is just an estimate, because again 90% of our commodity related activities is related to butane blending, and we really break that down as sort of a derivative of the crude oil change. It’s really a function of gasoline versus butane. Both of those products have a relationship to crude, so you can sort of predict the margin. But it doesn’t necessarily hold true all the time. So, think of the one, $1, $3 million as sensitivity, not as a hard and fast rule.
So, how’s that working out so far this year? Crude’s been better than our $35 average for the year. What we have actually seen is while crude has been up, gasoline has been particularly weak and butane isn’t particularly strong on a relative basis to crude. So that relationship with gasoline and butane to crude oil assumed in our original sensitivity, hasn’t really played out so far this year. It looks like when you get to the end of the year, everything should be as we expect. But so far this year we just haven’t seen it, which means we’re performing as we expected; we just haven’t seen quite the benefit we thought we might have, had that relationship held.
I’m going to touch just for a moment, strong distribution coverage, and this is really going to get into the philosophy of how we operate. If you look at the chart, you can see in ‘13 and ‘14, we generated significant excess cash. We also grew distributions at a very healthy rate. Also we recall that in ‘13 and ‘14 butane blending, commodity related activities were performing quite well. ‘14, we actually set a record. So, our commodity businesses basically streaming, it’s doing great. We allowed our coverage to expand at that time.
Now, let’s fast forward to 2015, commodity business is doing not as well, but we still have a very confident story. We’re still growing our distribution. So, there is some thought into how we run our business and how we set our distribution policy that is a function of looking at the risk within our business and trying to have a policy that’s fairly consistent, it’s make it through cycles without us having to be looked on [ph] in terms of how we manage our distribution. So that goes back to our guidance for 2016 and 2017, 10% growth this year, at least 8%, 17%, while maintaining 1/2 coverage.
I also point out that in that 1/2 coverage obviously is the current commodity environment. So that’s pretty robust. I think, it gives you an example of how we try to manage our business for the long-term.
Talk for a moment about our credit profile, I recognize a lot of familiar faces in here, so you’ve probably seen this slide or version of it many times. The story is the same, consistent. We’ve always talked about having a target of around four times total leverage ratio of debt-to-EBITDA that hasn’t changed. You can see in the chat that we’ve only even tested it once and that was back in ‘09, we bought Longhorn, didn’t have any EBITDA that came with it as our leverage ratio to go up. We did two things, we issued equity, that’s our last equity issuance; we’re sort of behind that deal in 2010 And then Longhorn and other projects started coming on line, they’ve provided just tremendous return, which is not causes to deleverage.
We do expect in 2016 see that leverage ratio increase. We ended the year around 2.8, 2.9. We’re going to be 3.4ish we think at the end of the year, don’t have, we still hope for a great leverage ratio and we should see, if everything goes as we expect, again the same pattern of deleveraging. Do we want to operate at 2.8, 2.9, I don’t know if we want to be that low all the time. But we are often asked when people see that room that we have and we’ll talk about in a moment in our capital structure, are we just going to run out and buy somebody or build something, because we can.
I think you can see this pattern right here, we’ve been doing that for quite some time. We could have essentially used the balance sheet capacity during the heyday if we chose to, to pay high multiples for acquisitions. We had all the tools that we have now, we’ve had for the past several years. So, there is nothing new about the position we’re in right now; it’s the same position we’ve been in. So, the point I want to drive home is that the same discipline and consistency we use to manage the balance sheet and make investment decisions is going to be the same going forward. Just because we have the capacity doesn’t mean, we go out like a drunken sailor, so to speak and spend it. It takes us a while to earn it, it’s a way for us to deliver value to investors, but it’s not something we plan to give away.
Balance debt maturities: You’ll notice our average tenure is 13 years on our debt, which is rather long and safe. You’ll also note that our all in interest rate is around 5%. Some of our fixed income investors in the room, if you were able to get it on a bond deal back in February, you’re welcome. So, the equity guys are worried about what we’re doing with the bond deal, you’re welcome as well, because 5% rate back in February, we’re pretty happy with. Because we have waited, obviously we could have waited, maybe gotten a better spread on the debt. But that’s another example how we run our business. We’re not trying to eat everything out of the margin all the time. We’re trying to get through cycles, manage the long-term. Our business is to create absolute value, it’s not to trade bonds. So, I’m not a bond trader; I’m here to raise capital and we were fine for the 5% rate. So, the equity guys, 5% rate should provide us plenty of opportunity to create value for you as well. Again for the debt investors on that deal, you’re very welcome.
Now, with our balance sheet, with our approach, we’ve got a lot of flexibility right now, if we see opportunities and that’s exactly where we want to be. When you look at our liquidity, we’ve got $1 billion committed facility, $250 million 364. We expect to generate about a $150 million of excess cash flow this year, already got one bond deal off that we received very well in the capital markets.
So really, if there isn’t anything out there really that we can do from a balance sheet in the financing perspective, we even think if we had do, which we don’t plan to, so it won’t be just in here. Given what we see right now, we don’t plan to issue that. But if a real opportunity presented itself, we do think we are on the few that might have a fighting chance because actually getting into the equity market and having a successful deal in raising capital on a reasonable way. Just with that capacity, we think we could easily raise about a $1.4 billion. For those that are paying a lot of attention to the slide, the nine times multiples, don’t freak out, we still think organic capital six to eight times, we are not changing the game volume. In this particular analysis, we assume that we also may do some acquisitions. And if we did some acquisitions, those would come at actually higher multiples, so we use and nine-time multiple on this particular analysis.
Now, we are going to move into the last couple of slides where I want to hit on competitive cost of capital and there is really a couple of points in here that I really want to try and drive home, again to help you understand how we think about cost of capital. You can see from the chart, bottom left hand corner didn’t quite get all the way down there to beat the Shell’s MLP but pretty close. We thought about, if we could just leave them off but we didn’t think that would be fair. So, we’ve put them on there. You can see where MMP is very well positioned. Two points here, the way we look at our cost of capital, it’s still competitive. Believe it or not in our own line, the cost of capital today for us versus the cost of capital today for us three years ago, you could argue as marginally higher but when you look at it over a longer term horizon, we’re not sure it’s drastically different. The good news is we’ve created it that way, which means we still have opportunity.
So, what is our view of our cost of capital? We think the yield plus growth model is probably the best sort of model we use, the dividend discount rate for MLPs. You can see the top of the chart here, current yield for us is 5%. And then, if you just look at our growth and break it into two broad buckets, short term being to 8% to 10%, which is fairly concurrent with what we’ve mentioned on distribution growth and then particularly long-term several years out, particularly long term growth rate. We are not saying we’re dropping off the 3% to 5% in two years. So, again, please don’t read more into it than what it is saying. It’s just saying that at some point, growth rates will decline when you get towards the terminal growth. And if we did that sort of compounded annual growth rate on that two stage model, it says from an equity perspective 9% to 11% will be what we would expect equity investors to demand about.
Combined that with our debt costs, which are between 5% and 6%, if you weight that 55% of equity, 45% of debt, that’s to maintain basically that’s four times max leverage ratio on EBITDA. It says our cost of capital at some place is around 8%, maybe little less, maybe a little more, around 8%. So, does that mean we are going to run out and do 8% deal, no it doesn’t. We are going to run out and do 8% deal. If we do that, we are not creating any value for you. We have to do better deals in that.
So what is our hurdle rate, we get asked that a lot of time. Well, the hurdle rate depends because we spend a lot of time looking at each of the deals that we’re looking at and we try and risk those deals and put the return required for each of those deals on those particular deals. Why, because if that’s what the deal demands in terms of the risk profile that it has, then the investors expect to earn value and a return on that. We don’t want to give that away. So, our hurdle rate moves around, so in there so maybe a floor 10% that’s probably an okay kind of approximation but it does move around, we don’t just supply from the standard 10%. So, this is how we think about cost of capital.
And I’m going to make one final point on this slide and I’m almost done. The final point is we view cost of capital with the very long-term horizon. We don’t measure our cost of capital everyday and say on Friday, it was 8% and on Monday it was 10% and on Thursday it was 12%; it’s irrelevant for us. And I know it’s an extreme example that you get into new cycles where cost of capital is up, cost of capital is down, markets are in term oil; it will be very distracting. How do you possibly know what you should invest in or not invest in it, fact is that typical gyration that happens in the market sometimes are more severe than others. For us, we try and keep an honest consistent view through the cycle to avoid those distractions.
So, at the end of the day, we put all this together and we’ve got strong underlying businesses, which you guys have heard about all morning long. Those businesses still have growth in them, which Mike is going to come back up and talk, even some more about. When you combine that with our strong balance sheet, which gives us the ability to grow, our balanced distribution policy which keeps distributions matching our business model, combine it with our access to markets and committed liquidity, the fact that we still have a cost of capital levels that we can get projects done and by doing so create value, they don’t have to work for free, we put it all together, even today and with a very difficult dark moment in the MLP space, Magellan still has all the tools it needs and all the capabilities to create value for you.
So, those conclude my comments. So, I think the plan is to turn it back over to Mike to talk about our potential projects and then wrap things up and head for lunch. So, I’ll turn it back over to him.
Thanks, Aaron. We’re almost finished. I just want to spend a few minutes talking about potential expansion projects, things that aren’t in that $900 million of things under construction right now. I’m sure probably, many of you and I can get to, we’re going to grow, the number has 500 million on the slide that we continue to say in excess of 500 million and don’t change that number. I’m going to talk about couple of projects here to give you some perspective on that but we still feel -- I feel that it doesn’t provide a lot of value for me to put a bigger number out there because when I look at the spectrum of projects that we’re working on, if I add that up, it could come up to a very big number but there’s spectrum of probability associated with that. And I don’t know if it provides a lot of value to you, if I tell you, I’ve got a $500 million projects in my backlog but then I don’t tell you that it’s got a 10% probability of happening.
And so, when we look at a list of projects, you have that spectrum, number one; and number two, it’s very difficult sometimes to even put a probability on a project because, you’re working on it. And I’ve seen projects that were 90% probably and not happened and I’ve seen projects that were 10% probable happened. So, without being able to provide context around an absolute number, if I would give you one, I don’t know what value it is. And then once I give you that number, let’s say it’s x billion and then the next quarter I say it’s a 1 billion less, everyone is going to be focused on what happened, when nothing happened, it’s just that’s the nature of project development on what you get done and what you don’t get done.
So, that’s why we resist going to a higher number. And I know that frustrates a lot of you but we continue to just doing that. I will tell you that we have a healthy mix of projects in that backlog between refined products and crude oil. It’s becoming more balanced, as I talked to you before with regards to refined products opportunities. Just to touch on a couple of -- I didn’t want to put a little color on it, and these are projects that are material and are moving much higher up on the probability scale, one of them is Seabrook extension that I talked about earlier. The extension to connect it into our distribution system, build dock over there, add additional crude oil storage, the probability on that project is getting much stronger, we’re hopeful. A caveat, everything I say in this section is if it doesn’t happen, don’t say I said it was going to happen because I’m not.0 I mean project is not a project till it’s done but the probability is looking very good, we’re hopeful that we can have something done in the next couple of months.
Another thing that’s rapidly developing is a new refined products export facility that we are developing in the Houston area. We’ve signed a purchase agreement for the land; it’s going to be a grassroots facility. And the probability of that is rapidly escalating and that’s got multiple phases. If I look at the first phase of that refined products facility and Seabrook opportunity, those two projects alone are $500 million plus capital opportunity for us under contracted fee base business.
If we go to the next steps or phases of expansion of refined products facility which is also starting to look very positive that number doubles. That’s just those two projects. I just want to give you scale that there are some material things happening. When we say that number is well and excess of 500 million, we really mean it, well in excess of 500 million.
So, I want to provide a little bit more color on that. We’ve also got a number of pipeline opportunities, now with the storage. One of those is something that we’re hopefully we would have a small announcement on by today. we haven’t done it yet, so I’ll leave that for then but it’s a potential joint venture pipeline in South Texas we’re working on. That’s still lower on the probability skill than these other two projects. That’s just a sense of how difficult is to give you a precise number when these probabilities are bouncing around. But these three significant projects out of the list of many that I can give you a little color on to maybe give you some comfort that as I said, when I say in excess of 500 million that really is well in excess of 500 million. And then all of these as usual, we target six to eight multiple to put those together on organic development.
Just couple of things I thought were topics of industry interest with regards to consolidation, and I’m sure you got questions on these. So, we just thought we hit them right at the top. There have been some large transactions. You probably haven’t seen as many of them as people would have predicated. I don’t know that that big of a surprise to us. Of course, we haven’t been the leaders in acquiring things, [indiscernible] people to ask. But when you look at -- when we look at the spectrum of opportunities, especially from a corporate level transaction, most of the opportunities set from distressed standpoint are in businesses that we’re not in. So, we’re not interested, I’ve never say never to anything, but it’s very unlikely we’re going to do anything that substantially changes the scope of the business.
We’ve looked at those kind of things in the past, even if it’s a distressed, even if the accretion is huge and it looks like a great acquisition, we’re very unlikely to do it. We’ve looked at those things in the past, we’ve been very concerned that the impact they would have on how the Company is viewed from its basic business perspective and would shy away from doing them. And I think there was recent transaction in the last year which you guys can know what it is, but where you had a very stable well financed company by a very large riskier business and my guess is probably most investors aren’t very happy with that. We’re very aware of that but we don’t go out and pursue those kinds of transactions, even though I can tell you every bank comes through with a presentation to try to convince us to do so, we don’t do that.
The other thing there too is you’ve got -- you do have a lot of assets that are owned by private equity guys that are attractive in many respects. When you talk about gathering systems for instance, you have contract back gathering systems in certain basins that are marketable, but you have a situation there in general we’re seeing as the private equity sponsors are not distressed, and this is not when they want to sell. This is not they want to sell at the bottom. So they’re patient and so they’re putting those on the shelves and they’re going to wait for better market. So, those opportunities aren’t really that actionable right now either.
MLPs, they’re the right organizational structure. I know everyone has had opinion on that. Our view is absolutely, it’s the right organizational structure. I mean if you look -- the problem areas have not been in my view because of the structure -- with the exception of IDRs. And obviously the stress on the MLPs structure, if you have a GP with IDRs, but that’s not rocket science. I mean if you just extend out the growth profile of any MLP with an IDR, you would expect they’re going to get a level where they’re stressed at the LP level because of the IDR burden. That perhaps is something that I can foresee change over time and I know probably everyone has got it and would like to get out of it, but can’t find the right financial agreement to put it together.
But the other issues I think that we’ve seen in MLP space in my view are not created by the MLP structure itself, it’s just management of the business. I mean if you overextend your leverage, and you invest in things that don’t have the kinds of returns you expected, it doesn’t matter whether you’re an MLP or not. I mean you’re going to have a problem. And so I don’t think it’s a structural issue, it’s a very efficient structure; it was set up originally to be the tax efficient structure for capital intensive businesses and I don’t think that’s changed, certainly hasn’t changed for us. And that’s that; we’ve had probably four summary slides today. So, I am not going to read this one.
So, with that, I’ll just open it up for questions.
First off, Mike, thanks for providing some I guess increased clarity on the well in excess of $500 million. But I was wondering if you can sort of comment about today versus a year ago on a probability weighted spectrum, whether it’s improved or it’s comedown? Obviously, you’ve highlighted two projects and so you’ve given us some clues as to where the next 500 and 1,500 comes from, but I was wondering if you can talk about the longer term backlog and how that spectrum waited probability exchanges?
Well, at this point in time and specially given some of these projects I just mentioned that are moving up in probability, I’d say our probability waited opportunities set right now is probably higher this year than it was a year ago. And it’s driven by some lumpy projects that are big high quality projects. And I’ll also say, I had a question earlier about have we reached the peak in capital deployment by the MLP industry. I think we may have; I don’t know for certain but it seems -- it feels like it’s unlikely we’re going to have continued overall growth in capital deployment in the industry for the foreseeable future. But that’s the industry. I think we’re in a very good position to benefit. One are one of the few that can efficiently finance a lot of things and a lot of folks can’t. And so it opens up many of our competitors so to speak for projects are handcuffed right now due to their lack of ability to finance and we’re not. So, I think it opens up an opportunity set for us. Distressed market, given our positioning is actually benefit for us.
How does the discussion with producers change in terms of contracts now? I mean three to five-year contracts came a little short given everything that’s going on at this stage right now. Is there an ability to sort of move the length of contracts out creating tension and moving forward with projects and so forth. Just wondering if you can talk about that a little bit just given that other producers are stressed not only with their IDR burdens but also rolling off of contracts into a spot market where there is any?
Well, negotiations with producer in terms of contracts is always stressed, they always want a short as possible and we always want as long as possible. That’s always the nature of those discussions. It’s a hard question to answer because there are no lot of producers willing to commit to anything right now. So, we’re really not in environment where you’re going to get a lot of support for projects. There is isolated areas where you can. We received a commitment to support our Eaglebine origin but there are some very strong need from that and it was a very high credit producer that has specific need. And that negotiation probably went somewhere any other negotiation on term and price.
But generally speaking, we’re not out looking at building any more long haul crude oil pipelines right now. I don’t know that anyone else is other than once already been announced. And so there is not a lot of those negotiations taking place. I will tell you and just to add on to the question Robb got about extending back into the basins with gathering systems. We understand we’re going to do that that it’s a different level. It’s unlikely, even though you’d love to have; it’s unlikely you’re going to get take or pay commitments for those investments. You are probably moving into what they do today, which is acreage [ph] commitment. We can’t show up and say we’ll build the pipe for you, we want take or pay when you got three other guys saying we’ll do it for acreage commitments. And so, we understand that that’s the probability that we’d have to accept at higher risk if we’re going to move closer to the wellhead for that kind of investment and balance that with the benefit. And the benefit to us is really at some point in time in the future always contracts are going to roll off. You’re going to have pipeline sitting out there with uncontracted space and it’s all going to be spot tariff and volumes and then deals.
And if our competition has the ability to provide that value chain all the way from the wellhead, if we don’t, will rely on third parties to do it, doesn’t mean we can’t do that efficiently through joint tariffs and other mechanisms. But it’s a lot more effective, if we’ve got the same capability back to the wellhead. So that’s why we’re focused on it. That doesn’t mean we’re going to go do something no matter and pay anything to make it happen. It still has to make sense. It’s just something we’re very focused on to see if we can find some opportunities that make sense because we think we’d be better off with that capability than not in the long-term.
Just two questions John Edwards, Credit Suisse. So, on the guidance, you said that you’re bearing in mind that you want to have at least 1.2 times coverage with the increase. And you’ve already indicated at least 8% for 2017. Is that still bearing in mind at least 1.2 times coverage?
Okay, thank you for that. And then the other is I don’t know if you can talk about this, but in terms of the high probability projects, if you could characterize definition of high probability?
High probability would be we’re negotiating contracts as we speak and the counterpart -- and we’ve agreed to terms, and so it’s a matter of getting the contracts done, which isn’t guarantee because we can always run into something that kills the deal but that’s what I would characterize as high probability.
And so, a low probability project would be one where you’re not in the midst of negotiations…
I agree to that point, yes. I mean talking to customers; it’s interest; it seems to make economic sense, but you haven’t agreed the terms with anybody. They may be evaluating other competitive alternatives to your project, it’s a whole spectrum of things that make it lower probability.
Okay, alright. Thanks for that.
Hi. In terms of potential gathering projects, is that percentage, I guess included in that crude pipeline, 10% breakout of opportunities that you’re looking at? Just trying to think of the magnitude of potential investments and what types of projects?
Are you talking about this slide?
And which part did you say, I didn’t hear the first part?
In terms of potential gathering projects [multiple speakers].
We knew somebody who tried to back into what the number was if I said anything, Paula kept telling me, if you tell them anything they’ll try to back into the big number. The gathering systems and that’s part of the problem here. This chart, if I am not mistaken, Paula, it’s probably things that we 50% probable or higher, so it’s not the whole thing. So, we did that on purpose to come back into it. Most of the gathering system stuff isn’t even on because at this point in time, we got less than 50% probability that is going to happen. But the spectrum of capital there is huge. I mean it’s -- there is acquisition opportunities that are $1 billion plus opportunities out there. And then there is smaller organic development opportunities that $10 million to $20 million kind of opportunities. There is a wide spectrum opportunities. The probability is low on all of those, at least at this point. We are in discussions with those folks but, anything is acquisition related and might be -- I mean just by definition, it’s low probability because for us especially because we don’t -- if they go out for an auction, they don’t easily win. And so, those kinds of things are in this chart. But the potential there is pretty significant. And if you go just look at the spectrum of private equity sponsored gathering systems in the Permian, which is some day, they are going to want to sell, maybe not today but they don’t want to own them forever. And there is a lot value there.
And you actually started the presentation with the chart detailing growth for Magellan over the past five years with 50% coming from crude. If you look towards the future in the next five years, would you say the mix is pretty much 50-50 as well?
At this point in time, I would say 50-50 is a pretty good estimate of what we expect going forward.
Alright, anymore questions?
Alright, well thank you for spending a morning with us today. Hopefully, we reinforced our positive message for you today and gave you some information you didn’t have before you came. And we appreciate your interest in Magellan. So, lunch is right now. Thank you.
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