Curtis Anastasio - Chief Executive Officer, President and Director
Daniel Oliver - Senior Vice President - Marketing and Business Development
Douglas Comeau - Executive Vice President and Chief Operating Officer
Steven Blank - Executive Vice President, Chief Financial Officer and Treasurer
NuStar Energy L.P. (NS) 2013 Analyst Meeting September 9, 2013 3:00 PM ET
Good afternoon, ladies and gentlemen. Thanks very much for coming to the NuStar Analyst Day in this very grand setting here in the New York Stock Exchange. I just want you to be rest assured that this room is free of charge to us today, so don't panic. It's really quite a beautiful setting. They do a good job here.
As you all know, late in 2012, we at NuStar initiated a strategic redirection of the company. And I'm going to skip these forward-looking statements, because I can't read it anyway. But the strategic redirection and the change in focus we started in late 2012 involved really going back to our roots, as predominantly our pipeline and storage terminal, fee-based company and to work very hard to minimize our exposure to the margin-based operations that we've gotten into. So a lot has been done in that regard. We're not done, but we're probably sort of a half to two-thirds of the way down the path that we set out to accomplish this strategic redirection.
As you all know, we've sold 50% of our asphalt refining and marketing business to a joint venture with a private equity partner at September 28, 2012, and raised $175 million for that 50% interest. We also shortly thereafter sold the San Antonio refinery that we had acquired a bit more than a year earlier, we sold on January 1. And importantly we eliminated the refinery hedges that were associated with that refining operation, which had really introduced even more volatility into NuStar's earnings.
And as it says here on this Slide, the proceeds from the sales transactions were used primarily for debt reduction, funding coverage ratio shortfall and investments and acquisitions and internal growth projects. Since money is fungible, in one way to think about this is, well, is that we took money out of the margin-based refining and marketing operations and we invested it in the fee-based Eagle Ford -- Eagle Ford area midstream. And more specifically, as you know, we did the Eagle Ford acquisition in December of that year from the TexStar company, which was a big expansion for us on the pipeline and gathering system that we had on the ground in the Eagle Ford.
So that was really the refocusing. As I said, we're good way down the road from the refining and marketing and the margin-based businesses to more of the fee-based businesses. And we're currently -- now our focus on the growth side is growing the fee-based side of the business. As I mentioned, we closed on our Eagle Ford crude oil pipeline and gathering system in December of 2012. And you'll hear a lot today in the presentation from the executive management team here about the Eagle Ford projects that we have going on in the company.
One of the things that you've seen in the press about us lately was the open season that we announced with regard to our South Texas crude system or Eagle Ford system, which is drawing a lot of interest and is expected to culminate in the next stage of expansion in the Eagle Ford.
We continue to develop certain of our storage terminals. For the first time in year, the storage market is a little weaker this year, but we have some advantage locations, where there are some very good return projects to invest further internally. So you'll hear a lot from us today about growth in the pipelines, but we still have some terminal opportunities that we're going to execute on.
We are seeing some progress now and leasing some idle storage tanks in certain of our markets. In the backwardated markets and some of the other economic developments that have happened, we are below our normal, say, 95% to virtually a 100% capacity leased out, which we had in storage business for years now, and more in the 85% to 90% range. And in some of the weaker markets, renewals are coming in at lower rates. But we have Danny Oliver here today. He's going to talk to you about some of that mess is starting to be cleaned up now. And we are leasing out more of those capacities, including certain tanks, where we had our fuels marketing people withdrawn.
I'm going to talk more about fuels marketing. Some of the fuel oil business for example, they were previously leasing NuStar tank, as they went through there was initially some difficult market conditions to lease those out and we started to get that done. And also on some of the idle asphalt, as we have shrunk our asphalt business, we did have success just leasing out most of our terminal in Northern California, which had been idle after the shrinkage or the withdrawal of the asphalt business from that terminal. That's now been leased to a major asphalt player.
So you're going to hear about progress being made on that front. And we are continuing to evaluate options for the Houston 12-inch line, whether it's -- I think we fairly talked in past in presentations about either bringing NGLs down the line or crude oil up the line or some combination of the two. There is a lot of interest to do all that and what we've been working through is really trying to find the best deal that's out there to do it. So it's a very, very valuable asset. I mean if you don't have a good enough deal, you can even sell that line for a lot of money.
So we're optimistic about how that's going to transpire. And also because of that recent market weakness in storage in certain of our markets, thank goodness, a large majority, it doesn't apply to, but in some it does. We're evaluating divestitures of certain underperforming terminal assets to raise some cash.
So we go to the next Slide. The fee-based side of NuStar's business is expected to continue to grow, based on what I just said to you. And this is just showing some bar graphs. And the blue is pipelines and the red is storage segment. And during the period 2006 through '11, the storage segment provided most of our fee-based growth opportunities. So we had quite a lot of growth in storage, and that was really the growth driver in that '06 to '011 period.
If you look at the blue, it's sort of steady with slow growth in the pipeline. So it was very stable, that was the good side of it, but there was not a whole lot of growth associated with it. The growth driver was in the storage and that was growing -- that was feeding our distribution growth then as well.
And starting in 2012, mostly, as a result to the Eagle Ford, most of the fee-based growth opportunities are now in the pipeline sector. So the storage is kind of leveled-off in the red and now you see the blue, starting to tick up and grow. And that blue is what's going to continue to feed the growth going forward.
Our fee-based EBITDA increased about $225 million between '06 and '13. And in the '13 storage segment, because of the reasons I just said, is projected to be comparable to 2012. But the 2013 pipeline segment EBITDA is expected to be $50 million to $70 million higher than it was in 2012. So again the pipelines are taking over from the storage as the growth driver.
Volatility and underperformance in the margin-based asphalt and fuels marketing segment put pressure on debt-to-EBITDA and it put pressure on the coverage ratio. And here you can see with these bar graphs, acquisition of the asphalt refining and marketing, and then which made money in the first several years, but then the subsequent underperformance of principally asphalt as well as our capital spending program required NuStar to issue equity or equity-like securities every year from 2007 to 2013. So we issued a lot of equity to really basically to fund the underperformance of principally asphalt. And just stay on side with the banks and with the rating agencies as best we could and for as long as we could.
Our margin-based EBITDA was basically flat from 2006 to '13, but down about $120 million from 2008 to 2013. And you can see that 2008, that $127 million, the $90 million red, was the first year of asphalt refining and marketing generate the $90 million, and then taking it all the way down to the numbers that you see in '12 and '13.
The fuels marketing segment, 2013 EBITDA guidance has lowered to zero to $20 million. So what's happened here, because this doesn't include the asphalt, but includes the bunkers and fuel oil and the crude trading and butane blending. So the problem really has been lower profitability and heavy fuels and bunkering. There's been continued reduced worldwide demand, increased supply, putting pressure on the bunker margins and the reduced supply of vacuum tower bottoms in fuel oil in the Houston market, they've been negatively impacting heavy fuel margins.
Now, none of this is unusual. Anybody who's been around these businesses for a long time is now they have up years, like you see the blue, the $37 million, the $68 million in 2011 and they have down years. The reason -- and right now, by the way, if you talk to anybody in the bunker business, I mean they are really suffering. A lot of traders have withdrawn from it altogether, laid people off, especially on the North American side of that business. So it's not unusual and it's not unique to us.
But what I want to take you back to is, why did we get into this in the first place? We got into this to leverage asset storage investments and we already have. So for example, in St. Eustatius in the Caribbean, where the storage market is weak, we got into this bunker marketing and expanded on bunker marketing there, because that operation not only generates profit or not, but they pay our storage segment, right now about $30 million a year. So before they can generate a penny of profit, they pay a market related rate to storage that they have to cover $30 million, and they're earning that $30 million, even if they make zero.
So they're making the $30 million from the customers, which in a good time they can easily cover and make a decent return on the business like 2011, 2012. Even '12 was a good year and we had a write-off there that affected their operations. But in 2013, when the market is much, much weaker, now what's invisible really in their perform is a fact that they are paying storage, the $30 million.
So the question you ask yourselves at a point like this is, would we be better off withdrawing from that business in one or more of those locations and leasing them to a third-party or should we continue in the business. Right now, the answer is, continue in the business. Doesn't have to -- it may not necessarily stay that way, but that's how it is right now, especially in this market where I just told you that it's very, very difficult to match the renewal rate or even lease the spare capacity you have in heavy fuels, because you have people left and right dropping out of the business, you know, traders who are getting in and out there all the time. So that's a big part of value that they add.
And the last point that here says, the segment guidance excludes losses from the 50% interest in the asphalt JV. As you know, we have it somewhere in these slides, but the Asphalt JVs -- the Asphalt results are deconsolidated from NuStar's results since we did the JV and it's just an equity interest in a JV. So the earnings positive or negative pass through that line and it doesn't affect our distributable cash flow per se.
So going forward, we do expect -- we already have less volatility and reduced working capital requirements in the fuels marketing segment. Then all that's left in that segment is entirely composed of the remaining fuels marketing operations since January 1 sale of the San Antonio refinery.
What's left in that segment, now that Asphalt is in the JV is the bunkering fuel oil marketing, which I just mentioned. The crude oil trading which is at St. James and the product supply, which includes the butane blending, which has been consistently profitable, that's going to be very profitable again this year.
We in response to the lower profitability and the bunkering fuels marketing, we recently entered into a back-to-back supply agreement for St. Eustatius for the third-party. Trader, that agreement will reduce our working capital by sort of an annual run rate of $40 million to $50 million, sort of the average working capital associated with that business in St. Eustatius and they are going to supply us on a back-to-back basis and that should improve our results about $5 million to $10 million a year. In addition have a less debt of course, primarily the reduced expenses. Say, full benefit of that will start showing up in the fourth quarter of this year.
Fuels marketing as I mentioned currently pays storage about $30 million in annual storage fees, which is a pretty significant number. That represents about 5% of current storage segment revenues. And again, we're always comparing that against what could we do with third party, how much and how quickly.
On the next Slide, mainly as a result of the Eagle Ford projects, the pipeline segment should be the largest operating income generating segment starting this year. And 2012 is a little bit of an unusual year in this pie graph, as to the right off that we had, but in 2008, you can see we were about a 70%, 30% business or 71%, 29% to be precise between the fee-base, pipeline and storage business and the margin-based marketing business. And now in 2013, which is as I say, a more normalized year, that's more like a 92%, 8%, so the margin-base business is now a very small portion of the overall business as I've said previously.
And just on the Asphalt JV let me say a word or two. Of course, you know we've done the JV and the investment in that business is not strategic to us. We don't need to remain in it, so we've been looking at all alternatives of how to exit. Now, one of the factors involved with this is, NuStar does provide the JV some credit support. We have an unsecured seven-year revolving credit facility, I guess, six years to go now, for up to $250 million.
The current balance is around $190 million and -- but it has been as high as close to $250 million. And it's estimated the yearend balance, which this could change because they are trying to drop down their inventories and reduce the working capital. But the yearend balance when we did this Slide, it was estimated around $225 million to $250 million. We also provide credit support, commercial trade credit, guarantees and the like of up to $150 million, that's down to a $110 million currently of guarantees and -- mostly guarantees, but some LCs that have been issued.
Now one of the keys to reducing our financial commitment to this has been to make further improvements in the Venezuelan Crude Oil Sales Agreement. This agreement started as an agreement in 2008 to buy 75,000 barrels a day of heavy crude oil from the Venezuelans, through amendments and negotiations that's now down to 30,000 barrels a day from 75,000. And we recently an amendment that officialize that, that's kind of retroactive to October 1, 2012.
But the other very significant thing about that is not just the volume reduction from 75,000 to 30,000, but they agreed to waive and release any passed liability NuStar might have had for under lifting on the original 75,000 a day. So that removed a very substantial contingent liability of the company, well over a $1 billion potentially.
Now going forward, we might want -- not we might want to, we do want to and will further negotiate this agreement to attempt to make further improvements, let me put it that way for now, and in fact, myself and couple of our executives are going down to Venezuela tomorrow to continue those discussions because one of the keys to further improving the deal with our partner or selling the interest is to get this agreement in as good as shape as we possible can to make the investment more attractive. So as I said, that's a live item. We are continuing to work on that.
We're also pursuing all the options regarding divesting our remaining 50% interest in the JV. Our JV partner is open to talking about it and has in fact been talking to us about acquiring that 50% interest, so that's also a live item. So there is a time clock on all of this, because in the case of the Venezuela contract it has 18 months to go. Of course, we're trying to do something about that much, much earlier. So all of this ends at some point. The question is how fast can you end it and get this behind us. This is not forever a problem.
The Asphalt JV's, I think I had mention earlier, the results were deconsolidated from NuStar, and that began in September of 2012. So what are we looking at now as we windup '13 and go into '14, while storage demand is weaker than it has been in the last several years. I mentioned we're making some progress on that 85% utilization to get it back closer to our sort of 95-plus percent that we have had for many years before this year.
We are looking into divesture of several underperforming terminals, that's really just in a few markets. And terminals that are making money, but really have limited growth potential compared to some of the other things we might be doing, whether it's Eagle Ford or elsewhere. We're starting to receive enquires into leasing tankage that have been idled by our bunker operations.
So as I mentioned, they were in several locations. They have withdrawn from couple on the West Coast, Mobile, Alabama. Now they are operating in Texas City in Houston area and in the Caribbean, when they withdraw from that storage that storage has to be marketed, and Danny and Doug are going to talk some about that, and they're making progress on that. Some of those tanks are being leased up as we speak, but that has been part of the short-term weakness in storage.
And on the growth side, we are pursuing tank expansions and additional crude railcar offloading projects at certain of our terminals. You're going to hear more from Doug about unit train number two at St. James, a unit train project for the West Coast and some of the other investments we're making in a few of the terminals. Again, most of our growth capital is on the pipeline side, but we do have some good terminal opportunities too.
Another good news item for us is completion of construction of our dock in Corpus Christi. We have a dock already and just talking about an expansion of that dock, because dock space is the bottleneck in Corpus. Everybody wants to be in Corpus, everybody wants to get out to the water. So everybody has this problem now with all this Eagle Ford production of congested dock space.
We do have -- we're blowing and going on that now, because we recently got our final approval or permit from the Army Corp of Engineers, which allows us to start dredging on the expansion and to get the dock project going. And we still expect that to be up and running around May of 2014. We're going to work as hard as we can to get it started earlier, because everyday we gain on that is money to us. So we'll see if we can do it and maybe add some ships or accelerate the opening of that project.
The South Texas crude oil project open season, the one that's open right now through to the end of the month, is drawing a lot of interest. And we fully expected that when that open season closes, we're going to have support for the next phase of growth in the Eagle Ford on the South Texas system. And those projects coming in 2014 and '15 in that region, and Doug and Danny will talk about those.
I mentioned what's going on with the Houston 12-inch, something is going to happen there. I mean it's not just going stay idle. And we also in our company right now, obviously, because of the shortfall in the distributable cash flow and the debt, we're implementing strategies to reduce working capital. I mentioned the St. Eustatius deal, there's more of that we can do on operating expenses, particularly associated with the fuels marketing segment, since their profit has dropped. And of course, we're still working on reducing our financial exposure to the asphalt JV and divesting our remaining 50% interest in the JV, which will be add up sooner rather than later, and it's the sooner that I've been on everybody's, but to do.
On the next Slide, as '13 comes to a close, between the internal growth projects, the asset optimization, the working capital reductions and cost reductions, we're going to see big improvements in distributable cash flow, starting this year, but really getting into '14. And we're going to look at things that really we've never looked at in this company in terms of cost reductions, including G&A. Our G&A was supportable for a long time at a pretty high level, it's not right now, so we have to cut it. And it will be really significant cuts in all areas of our company, until we get right-sized and we get this problem behind us.
2014 and 2015 financial guidance, I wish I could give you more today. You will get some sense of it today, but it's really going to be in the fourth quarter of '13 as we get to that, because we will have completed our budget process, we'll have been through the board, we'll have all the direction we need from the board, what they agree with or don't agree with in the budget and we'll be ready to really present a full blow in detailed presentation in a couple of months time, on particularly '14, but also an outlook on '15. And by then, we'll have the South Texas crude pipeline system open season behind us, and we'll know, we'll be talking about the next phase of expansion there, and we'll know how that cranks into the '14 and '15 numbers.
So with that introduction and overview, let me turn it over to Doug Comeau, who is our Executive Vice President and Chief Operating Officer. And he's going to update us a bit more in depth on each of the business segments.
Thank you, Curt. And I've got some very good news for you as far as what's happening in our business in and around the pipeline segment. And it centers around one of the biggest oil shale plays in the United States and it's the Eagle Ford oil shale. You know, we've been very fortunate to have assets right there on the ground when the Eagle Ford shale production started up. And so we were able to take some of those assets and convert them from oil or under-utilized assets into very, very profitable ones. But the Eagle Ford production continues to impress us. Every day we see new forecast coming out of the Eagle Ford and everyday we see that those production forecast continue to go up.
We know that there is over 5,000 permits that are already been issued for wells in the oil -- oily window of the Eagle Ford shale and just in itself that would equate to another 10 to 20 years of drilling going on in the Eagle Ford and production today is in the 800,000 to 900,000 barrels a day range, projected to go almost to 1.6 million barrels a day of oil production. And like I said, each new oil forecast continues to show that the Eagle Ford is expanding at a very, very high rate.
I wanted you to kind of look at that yellow line. The yellow line, we just put on there to show you about the takeaway capacity that is in Eagle Ford. The yellow line just takes the pipeline data that's out there and then uses the nameplate capacity of that pipeline and we added all those up and we put these on the chart, by no means is that the production or the takeaway capacity that is actually in use today because -- just because you have the pipeline capacity, it doesn't mean that you have the terminals or the pumps or in fact getting it out over the dock.
As we were just talking about we have -- our pipeline capacity is in excess of 200,000 barrels a day, but today because of dock space and meeting more robust Corpus Christi we are limited to about 100,000 to 105,000 barrels a day over the dock. So with that, the oil rings in the Eagle Ford is running a 180 rigs.
I was talking to somebody about that number, because it didn't seem like it was too of a high of a number, but really it's pretty impressive because it used to be that to drill one of these horizontal directional drills, it took about 30 days to drill, but with the pad drilling technology and being able to go in multiple different directions, they have got that down to some place into 10 to 12 day range and instead of costing the producer $10 million to $12 million for a well, they are getting that price down into the $5.5 million to $6 million range.
So you can see that the Eagle Ford shale, knowing that it's there and knowing that the production cost are coming down, that this is going to be a significant play and we're right in the heart of it and you'll be able to see that if you want to kind of put the head to Page 19, you can see the map of where we're at in that oily window.
The fact that we were the first mover in having one of the first pipelines in the Eagle Ford oil shale play it was a very, very helpful. We have now completed six projects in Eagle Ford and those six projects are reactivating the Pettus to Corpus Christi line. We have leased asset to Coke, a reversal of the eight-inch Corpus to Three Rivers refined products pipeline. We have a new connection of 16-inch, Corpus to Three Rivers crude line that we connected to our new 12-inch acquisition of the TexStar crude oil pipeline system.
Again, you can see those maps on Page 19. We had a construction of a new 12-inch crude oil pipeline for Valero that allows them to take crude from Eagle Ford down to their refinery in Corpus Christi. We have a new terminal in Oakville just outside of the oily window where we can see trucks and we have four LACTs right there at that truck unloading terminal.
It is also our major pumping station that takes crude that we gather from our South Texas crude system that we bought from TexStar and the north system that goes up into Orange County, and at that Oakville terminal we're able to then pump down the 16-inch to North Beach. And we recently also have a Pawnee Terminal pipeline connection that we completed for ConocoPhillips.
These projects cost about a $185 million. Our EBITDA is $35 million to $45 million, but remember these are in a fee-based type businesses, and these are backed by five and sometimes 10 year take or pay type agreements and so they are very, very solid EBITDA producers.
In August, NuStar completed a construction of that 100,000 barrel terminal at Pawnee. It has four truck offloading -- truck offloading facilities there and that connection is a 12-inch connection. It has a capacity of up 100,000 barrels a day, but that particular pipe on ConocoPhillips we have a minimum take or pay contract of 30,000 barrels a day and they've agreed to ship 30,000 to 60,000 barrels a day on that Pettus line. And it is a 10-year agreement that supports this project. Even with that capacity of those pipes, again trying and gets all that crude out on to the water where they want to take it to the markets, whether it'd be to loop or to Houston is the challenge.
And we have just recently, just this last week, got the final approval from the Corp of Engineers to ahead and dredge, drive our piles in putting in a whole new berth at Corpus Christi. So we have already engineered all the modules. So once those piles are driven, we can then set these modules on top of the piles and we expect to be to the place that where we will have more than 300,000 barrels a day of export capability out of North Beach some time in the second quarter probably around May of 2014.
The total spending on the project, which is a ConocoPhillips, that project is a $120 million to $140 million. We should generate $50 million a year of EBITDA based upon the minimum take or pay that ConocoPhillips has signed up for, which is the 30,000 barrels a day. You're going to see a small benefit in 2013 as some of those barrels get pushed into the line of Pawnee, but most of the EBITDA, which is very much the growth on the pipeline segment is going to be in 2014 after we complete the dock.
We've had so much interest in this South Texas crude system as they continue to expand the Eagle Ford is that we have decided that we needed to expand the line. We barely got the system back and got them all up and running with NuStar technology with its SCADA systems, but we have gone open season on July 17, and we look for commitments and we have the project broken in to really two phases.
The first phase of the project centers around taking and putting on booster pumps and bigger mainline pumps in order to put crude down the line. I mean these are all back by the fact that our shippers and the producers are coming to us and say we need more flexibility, we need more capability of transporting crude to the water and get it out to the market. So these proposed pipelines are again are backed by this open season.
The first phase is I said was just the powering up of the pipes that we existingly have, that would add 35,000 barrels a day of capacity. The cost is very, very minor in the $20 million range. And we believe that the open season for this phase one will easily get past the 35,000 barrels a day commitment on that pipe.
The second phase of that, which will take about 65,000 barrels a day of commitment at the end of the open season, will be a much bigger project, it would entail some new pumps stations on our 16-inch. It would require some new tankage at Oakville, some new tankage at North Beach, and actually we're looking at doubling, looping our 12-inch line from Highway 97 into the Oakville terminal.
I mean we just barely, like I said, got this all up and running for our customers and they're already coming to us and asking for more from capacity as these production and these wells continue to get drilled. So we're looking really forward to seeing in this open season, which will in the end of September, we will see exactly what kind of a phase project we have. But it looks very, very promising for the growth of our pipeline segment.
So we continue to push through and get additional capacities in a condition or additional throughputs, as we talked about on the pipeline map that begins on Page 19, the next page, our 8-inch Corpus to Three Rivers line currently is running some place in the 16,000 barrel a day range, our 12-inch Three Rivers to Corpus line, 37,000 barrels a day. As I go on through, we're currently running around a 189,000 barrels a day of crude out of Eagle Ford into the water. And you can see the different projects that are slated or that will be refinished along on the way there.
So just today, again, just looking we're shipping 189,000 barrels a day and keeping up with as our shippers want more barrels. Many of you've seen this map over in oil again, but it really depicts in the green, what is the oily window of the Eagle Ford Shale, the kind of the wet region, which is wet gas window, which not only gives you some oil, but a lot of NGLs and some natural gas. And then yellow or gold region there, which is primarily a dry gas region, which would still be needing to take into processing plants.
But you can see that our assets are very, very strategically located right in the heart of all the production that is there in Eagle Ford, whether it'd be in Frio, Dimmit, La Salle. Orange County, we have pipes connecting and we have the ability to really provide, what I can said it to be a premier solution for the producers and the shippers in order to get their barrels to market.
The storage segment for the past years has been our bread and butter. It has been our growth opportunity. And the outlook for the storage segment is in this backwardated market is to be more flat than a growth opportunity. First off, some of the tanks and approximately a third of our tanks come due every year as our contracts roll from year-to-year because we generally have three, five and ten year contracts on the storage. So every year we're out there remarketing the tanks that have -- that come up.
Some of those tanks as we went to -- the market being a little bit over tanked or having some downward pressure on the rental rates has been completely offset by the first St. James rail offloading facility, which was completed in April of 2012 and it has been a great success for St. James.
We have been able to take that unit train, which they thought was going to be rated for 70,000 barrels a day. On the unit trains, we've been able to do as much as 100,000 to 110,000 barrels a day on a unit train. We take a unit train and offload it in less than 12 hours and so there are several days that we actually were getting two trains a day, but mainly more than a train a day is coming into the St. James complex and getting unloaded and put into the tanks for producers, mainly out of the Bakken type crude areas.
In addition to that we had added tankage at St. James, some 700,000 barrels a day in the first part of January and also we added 1 million barrels of distillate storage at the St. Eustatius terminal for a major oil company in South America.
Approximately 35%, a third of NuStar contracts come up for renewal each year. The renewal rate are different in every market, whether they'd be the West Coast or East Coast or the Caribbean, all depending upon the amount of tanks that are available at that time. We have some seen some areas where the renewal rates are actually higher than they had been in the past and have had some success at re-renting tanks for three years at higher rates.
But the most part -- most of the tank rentals when they come up for renewal are seeing the downward pressure of the backwardation and we're seeing something in the neighborhood of 10% to 20% reduction in renewal rates when we do renew. We do have 10% to 15% of the capacity of our tanks that is an opportunity for us to continue to lease. We have approximately 2 million barrels that we are at on the market for today in order to find tenants. We have 100,000 barrels a day in Portland, which was part of our bunkering fuel oil business up in Portland that we cracked it from.
Wellington we have about 400,000 barrels of heated storage. Point Tupper 500,000 barrels of heavy oil crude, pipe storage and about 1 million barrels in Blakely. Now, Blakely has a probably a maybe a repositioning of those tanks, instead of those being fuel oil business, we may be able to convert them, they are floating with tanks and we maybe able to convert them and be product exports to South America and to other countries as we would reconvert them into maybe some distiller type storage. Yes, the fuel oil market is that flat.
There are some terminals that just have not produced the EBITDA that we wanted them to produce, specifically like Piney Point. There is 5 million barrels of tankage at Piney Point. It's a completely contango play. If you don't have a contango market, very few people are going to put any barrels into Piney Point. So we're looking for some alternatives for Piney Point through the divesture there or real estate option, something along those lines.
There is other properties that we have underperforming. We have a terminal in turkey and some others that we are looking at as we go into the budgeting process of taking them, getting the money for them and then putting them to work in this -- for all the expansion and where we know that we get it, a great return for our invested money.
We talked about the unit train in St. James. We're up to having two unit trains in St. James and we have a commitment from a third-party that supports the construction of the second unit train. That unit train -- the first train was completed in April of 2012. It's been like I said -- it's been very, very successful doing more than a turn a day on the train.
The second unit train is $45 million, and we expect it to have it serviceable and ready-to-go in the last quarter of this year, but specifically some place around December. Then your EBITDA income from the second unit train again committed and again as a take a pay contract for three years, it is $15 million to $20 million range.
The success story at St. James really, really continues as we originally, when we bought that facility we had 3 million barrels a day of tankage. We currently have 9 million barrels of storage at St. James and just recently completed 700,000 barrels of expansion in January of 2013 and we are in continue discussions with several major oil producing and trading companies about building them more tanks at St. James as the drain oil out of the bottleneck inland crude production and that inland crude production is either getting their by pipe or by rail.
And if they are going by rail they will point that rail in three directions. They will go to the West Coast, the East Coast or the Gulf Coast where they can do their trading opportunity and the trading opportunity that you're going to take into the Gulf Coast, if it's going to go by rail, you really would go to St. James where you're connected to loop. So we see that as an opportunity for trains coming into St. James, in additional short capacity for the storage segment.
Also strongly have some interest in people wanting us to add heat or steam to the second unit train facility, therefore they could take undiluted bitumen out of the Bakken, bring it down to St. James, heat it and unload it, and put it in heated tankage and use it for blending with other crudes in order to get a crude that fits these medium-sour barrel refineries that are in and around Louisiana area.
Effective July 1, 2012, NuStar began to store and throughput Eagle Ford crude at the NuStar's Corpus Christi North Beach storage facility. And again as I said, the big item there in our storage at North Beach is just to be able to get more barrels out over the dock and to market and we plan on having that completed in the second quarter of 2014 or in May, but the railcars provides flexibility to shippers and they like that. They not as much committed to taking a space on a very large pipeline and happen to take that take or pay for a long period of time, especially in this area where we have the real traffic. And we think that we have opportunities for Pt. Tupper, Canada as a terminalling opportunity on the East Coast.
We've had some people that we have been talking to, not only about Western Canadian crudes, but also NGLs that would be taken to the terminals. So there is a opportunity for Pt. Tupper to have additional EBITDA coming from unit trains or trains going into the -- we'll start probably with manifest trains, something in the 16 to 20 car-type range, heat those up and then put them into tankage and get them out or build bulk and then be able to put those crudes to market.
And we plan to do exactly the same thing out of Vancouver, Washington and the terminalling opportunity. We'll start small with some sort of a manifest operation to bring train or crude in by rail. We'll build bulk there and maybe able to supply the West Coast refineries with some sort of a blended crude from the Bakken or for some like crudes there. So we have some very, very attractive opportunities coming our way both in the pipeline segment and in the storage segment.
So with that, I think that covers my section. And I'd like to go ahead and turn it over to Steve Blank.
Think you, Doug. You may know that in August, we finished a debt financing, $300 million of senior notes, which was closed. And I think that says August 19, it was a coupon of 6.75%. Maturity is 7.5 year deal. Unfortunately, during the deal, Moody's lowered our outlook to negative. So we're Ba1. We were stable, they put it to negative. That was a little bit unfortunate since they had told us the week before that we'd be stable. So we think that cost us about 50 basis points on the coupon and during the middle of -- after we launched the deal, changing the outlook to negative.
Our next scheduled debt maturity is a £21 million, U.K. term loan that comes due in December of this year. And we may look to issue some additional junior subordinated notes depending on the size of our capital expenditure budget for next year. As you've heard, we're in the midst of putting that budget together. And at this point really don't have a good enough feel on what the size of the strategic spend will be next year, because much of it depends on the outcome of the open seasons.
That junior subordinated note structure and we did won in January of this year for $403 million, accounts not as debt for purposes of our calculating or debt-to-EBITDA covenant in our bank financing, so it's very important. Under our revolver and our other bank debt, we can account up to 15% of our total capital, which is about $750 million of this type of issuance and not have account as debt.
This shows our maturity schedule performed for the $300 million of bonds we just raised last month. You'll see the 13 maturity that's that £21 million term loan in U.S. dollars. The $400 million junior subordinated note that we did in January, is a 30 year deal, but we show it getting caught in year five. We have the option to call that at year five. So hopefully, at that point, we wouldn't need that type of security in our cap structure having gotten the debt-to-EBITDA ratio in much better shape and would see ourselves calling in. And that's how we've modeled it here. And then you see the maturity and 2021 for the for the $300 million, a bond deal that we just did.
And then my last Slide is really just a historical view of total strategic spending in the company. You can see it's ramped up quite a bit in 2011 and 2012, initially on the storage side, but substantially and more notably this year on the pipeline side, in 2012, I mean to say. And then in 2013, we expect the strategic capital to be in the range of $350 million to $375 million, so quite a big spent for our company. And in a couple months time, as Curt mentioned, once the budget is finalized, approved by the board, we'll be out giving specific times on the strategic spend for next year and the outlook for the company EBITDA and coverage ratio, and so forth.
So that concludes my brief commentary. And now we'll be happy to take any questions you may have.
Curt and team, appreciate the update on some of your proposals to get your coverage back to one times. Can you maybe provide a little more color as to the mix of where you see the improvement coming from between investing in pipeline segment versus cost cutting and working capital savings and so forth?
Yes. Well, it's going to be everything, right. I mean we're going to make sure we've exhausted every possibility and turned over every rock on closing that gap on the distribution coverage. So that's why we're in the midst of right now. I think the EBITDA enhancements that we've talked about are mostly going to come from the projects that we talked about in the Eagle Ford and then into the specific terminal project, St. James, and some of the others that we mentioned there, Vancouver and so forth.
But at least at this stage, there is no question that a component of this is going have to be cost cutting, a significant component of it. And we're going to have to be very judicious on capital. We're high grading our projects as the capital is going on into the best possible return projects. And as I mentioned, we're going to look at cost reduction in areas that we really haven't seriously touched until this point like -- including G&A.
So in combination with that -- and then we have asset sales targeted, somebody gets them cash in early in the door, somebody get cash in later, because there is a sale process involved. And if you do something like, Doug mentioned say, Piney Point, if we come to the final decision -- and that's like, when we talk about 10% to 15% storage capacity under utilized, you got that 5% right there in one location, as it makes a lot of money in the contango market and don't make anything really in the backwardated market.
So that's different lives over the years, it used to supply heavy fuel oil to a atomic power right there. That's history. So it's now facing a reality of today. And if you do have to go to a demolition or sale a demolition, you do could get quite a bit of money. That's a very valuable piece of property. Very subtle -- net of some cleanup costs and all of that, but there is no big environmental there, we know that already.
So it's just a matter of when does that cash come in. When do you factor into your plans. So all of these things, I can't tell you that I can give you a exact percentages, but it's not going to be 90% of this comes from EBITDA improvement and 10% of it comes from cost reduction. It's going to be a much bigger component of cost reduction.
And as I said, being judicious on capital and high grading our capital project and then to the extent we need to, we plug in the asset sales on these either underperforming or completely non-performing assets and some of them are going to have values. It's not just going to be industry players, who will look at some of these properties and say, okay, I will pay you, 10 times, 11 times EBITDA or whatever.
But there maybe higher value realized just from the underlying real estate value depending on the location. So it's going to be -- I haven't given you precise proportions, because I don't have the answer to it. I have a pretty good, but its going to be a significant component it is that's going to be on the side. It's not going to be a minor component of it.
Just a follow up on the asset sales, can you give us sense of what's the potential order of magnitude could be? Could this be replacing equity offering as in the future given some of the terminal asset sales that could take place.
A lot of it depends on the final list and how much what we actually have to do. If you do only a small amount and maybe you're talking about like $50 million, if we do a lot, like I would think a lot at this point, it would be something like $300-plus million. So it really depends on the best -- then it goes back to the question you just asked, what's the best mix, as we go through this process in next say, seven to eight weeks, that gets us to where we must be, because we're going to get there, because we have to. We've got to get there on distribution coverage and we've got to improve our debt situation.
So we're going to, because we have to. And so it's -- what's the best mix timing, amount and everything to get you there. But we could, you know, if we have to depend heavily on us in sales, we could raise a lot of money doing that. Now we don't want to sell EBITDA either, right, because that's your future. So you got to find a sweet spot, and I think we will and we will, because we have to. I don't know if anybody on the panel want to add something to that.
Just to better understand your commitments to the Asphalt JV, you have, I guess a current commitment of $190 million out of the $250 million, so your rather $60 million, you are on hook for further revolver and then another $90 million in guarantee, so another $40 million, so you're up to $100 million of additional commitments that you'd be on the hook for, and that's cap at $400 million or is there any reason to think that there could be additional funds that are committed to this JV?
No, we're not required to commit any additional funds to the JV. I mean those are the max. And I don't know, Steve, do you want to add.
No, that's right, I mean the new storage facility is $250 million. As Curt, mentioned earlier, we've got close to that, because three cargos have been lifted in a very short period of time. It's down $190 million and we think it still may -- it could be as high as $225 million to $250 million by the end of this year. It depends really about liftings, candidly it depends on some of the conversations that will be held this week with the Venezuelans.
The guarantee facility there's only about $10 million or $12 million available seize under that. People that didn't take our credit partially because they know as, and I just said, we won an LC for now and then maybe we get open credit, and then there was about a $110 million of guarantees.
And this is for everything for New Jersey, light and power or railcars or stuff like that. So it's operational issues. Okay. But if somebody were not to take our credit and we have an obligation to post an LC, the JV pays for that. If it gets drawn on and it becomes funded debt, it then is a very much akin to what is news for our facility, but in separate.
In other words, we get paid a 1% profit on whatever the cost of funding that letter of credit would be. And that's pretty much our financial commitment, unless you decide that you want to continue invest in the business, which is not likely, strategically it just doesn't fit with us anymore.
And Steve, I guess I'd let you to pontificate little bit more on the balance sheet and thoughts on how you dig out of the whole that you're in with the downgrade. And you're finding ways to the junior subs to finances for now, but is the strategy to cut your cost -- cut your way through cost and waiting for EBITDAs for these high referring projects relying on, I mean this is part to Curt question too, but relying on these projects that you can come up with the Eagle Ford to plan the financial whole. But when you get into a whole like this, it's just hard to get out of that cutting cost, unless you come up with some really good projects. And what's your confidence that what you're hearing from those on this open season that you're the project they want to support?
I'm going to handover to Steve. But we're very, very confident in the open season and expansion to address the last comment. And I'm very confident overall, because it's just going to be a matter of what's the best mix to close this gap. I mean it's all achievable. It's just going to be how do you do it with the least possible pain. And it's not going to all be on the back of the shareholders. I'm a shareholder and not wanted to be in the back of shareholders. Everybody here, including the people on this panel are going share in the pain of coming what the answer to this question, to this problem.
So I'm going to hand it over Steve, because you want him to talk about a little more about fortifying the balance sheet. But I'd tell you this I feel a hell of a lot better this year than it felt last year. I mean last year we really were in a problem. We've taken the steps that I just mentioned. And yes, as you rightly pointed out, we still have a hill to climb here. But it's a heck of a lot and less of a hill, when I was working at a year ago or a-year-and-a-half ago at this time. We just got to do the rest of it. Go ahead Steve, he wants you to answer on the balance sheet.
On the balance sheet, I think as Curt has mentioned, it's going to be obviously a combination of cost cutting. The projects which Danny and Doug can speak most to I think in terms of the prospects there, because fortunately they are low multiple projects and we're fortunate enough to have quite a few pipelines and the opportunity in the Eagle Ford, because of our legacy position supporting for where or when from Diamond Shamrock Refinery. So it's great that we have this, because it would have made it lot more difficult for us candidly, if we didn't have this pipeline opportunity in the Eagle Ford.
G&A has always been high for us. It's been high for us compared to our peers, if you will. So I think we have an opportunity there to make some meaningful movement as well. And Curt alone not giving a set percentage kind of alluded to significant savings we could realize there. We are fortunate enough to have that treatment from the junior sub notes. So it can keep us for a time out of the equity markets. And the hope would be once we restore the coverage ratio, and can show some distribution growth prospects the stock should we rate and the public market would be more parallel to us, then it is now, because obviously, we don't want to be issuing common equity at these levels. So that's my best shot at answering your question.
I just asked though. One other question, so you remain a 100% behind the current distribution?
We have a lot of work still to do on the budget, okay. So I would not be committed to saying at this point, I'm a 100% committed to maintain the distribution. I think we have to look at the budget, which entails taking a look at these open seasons and what that means to our capital spend and when we spend it, and what it means to EBITDA. Because if we found ourselves in a position, where we had to borrow money for a significant period of time to maintain that distribution, we wouldn't want to do that, because there is the debt-to-EBITDA ratio, there is the rating agencies and so on and so forth.
In the last two years, what we've had is the ability to really plug that shortfall on a couple of ways. This year we sold the San Antonio refinery for a $115 million. It was not generating any EBITDA. As a matter of fact I suspect its loosing money at the moment, so that was kind of found money. The year before we had the Lindsay Goldberg joint venture, which brought in a significant amount of money, $450 million of total proceeds, including the $175 million that they paid us for the equity. But you need to cover the distribution on a recurring basis and those were non-recurring items.
However, we do have, I don't know, eight to 10 maybe assets that either make very little EBITDA or lose a couple of million of EBITDA. We really don't have any big dogs, like Piney Point probably loses $2.5 million a year. If contango was in the market, we'd make $10 million there. That's historically what we've made. Turkey is a contango facility. We've got the Houston pipeline, which is idle at the moment, which is very valuable, but do we build it for two years to get to the NGL opportunity or is it more valuable giving everything else that faces the company to see if that's worth more to somebody else.
So there is a lot of unanswered questions David. It makes it very difficult to speak definitively about distribution.
Without contradicting anything Steve said, I'll try to answer, just in like the capacity of CEO, I haven't even looked at that as a solution yet, because I don't feel like we're anywhere near, all the other things we can do on the cost side and on the revenue side to answer that question. I mean, without contradicting anything Steve just said, because really it's a board matter, ultimately right. It's not going to be Curtis Anastasio or Steve Blank who would decide to make the change to the distribution, negatively or positively.
They hear everything management has come up with everything. Management recommends and they make that decision. But I feel like we are nowhere done on the cost and revenue side before we can -- seriously I haven't even looked at it. I haven't even considered that as an option yet, because all of our energy is on everything else we can do to bridge that gap.
Steve, when you'll give us the guidance next quarter for '14 and '15, are you going to include some of the numbers that are kind of behind everybody's questions here?
Yes, I mean we may not have getting better arrangement. I am not sure we would bake in if there are going to be assets sales assumed, I don't think we bake those in. I think personally, again, it's a board matter. But personally I would want my budget to be more in my control than what somebody might pay me for six or 10 other things that we might consider smelling, if that's what we decide to do.
So Curt when you were answering the question on cost cutting, did you have in mind some of the reduced cost to go with asset sales or where you thinking more on this SG&A, frankly.
No, I was thinking of SG&A.
Totally separate, really. It's really SG&A and we're working on those numbers very hard right now. They just have not made it into -- but we got to see that next after the budget.
Regarding your visit to Venezuela in the upcoming week, without putting you at a negotiating disadvantage, what range of outcomes might you pursue? What types of things might we expect in terms of scenarios?
Well, I think the range is pretty obvious. It's everything from terminating the contract now, which has minuses as well as pluses to it because it is good asphalt to crude. It's not priced correctly at the moment. And maybe the volume coming, it still is not optimal, but everything from that to a ramping down of volume overtime to price discounts, so it's really price, volume, term, all of those things are going to be raised by me in these discussions and we'll try to get the best answer that we can from them.
And it may not all be resolved at this meeting. I mean, I don't want to put too much weight on just one meeting, but we have made substantial progress with them over time and we'll continue to work on it. The question of pricing is not going to be one that's new to them, because talking to other -- our people talk to other major refiners, who take the same grades of crude oil and all the feedback the Venezuelans have gotten is you're out of the market now for North American refiners. You know, your pricing formally may have been fine a couple of few years ago, but now it's not reflective of the realities of Canadian heavy crude and other crudes that are available in North America that were available in volumes that they are today.
So that one is not -- is not news to them. They get a lot of pushback. One major refiner that has a contract with them, coming up at the end of this year has -- we are told has told them we're not going to renew unless we get a big price break. So this is something that they are fully expecting. The harder part I think is on the volume side to kind of workout with them, how could we eliminate or ratchet it down over a shorter span of time and under the current contract so, all of that will be on the table, price, volume and term.
When you think about the capital opportunities in front of you, capital project opportunities and how you try to high grade, can you talk a little bit a just about the criteria, moving forward number one. And then number two, as you think about potentially the opportunity set in front of you, how do this -- perhaps JVs or other type of combinations sort of fit into how you might be thinking about it going forward?
I am going to turn it over to Doug in a second because he reviews all of the capital projects before they get to me. But basically what I'm looking for here is not just to return, but how fast is the cash coming in the door. And what's not just a cost, but the quality of the overall project, the counterparty and the quality of that scope of project can we create it in in-time with low risk and as fast as possible. But we may have to, when I say high grade, really focused on the highest return, fastest cash flow and best quality projects this year, at least for the next year or two.
Even though, people may have feel perfectly good projects they're putting in front of the management team, we can't do it all, right now. And that with all these leverage we've been talking about, our cost reduction and revenue enhancement that's one of them. Especially on the debt and these two metrics we keep talking about debt and the distributable cash flow coverage that how much capital we can spend and on what projects, is definitely one of the leverage we're going to be looking at this year. And we're not going to spend as much capital as project opportunities that we have, just not, because we can't do it. But the ones we do are going to be very, very good on the criteria that I just mentioned. Doug, you want to add?
Well, I would say that we would mainly be looking at wherever the capital is going to go, it's going to go into the growth areas of our business. And you look at those growth areas and you got to come back down to the Eagle Ford. The storage business with the backwardated market isn't an attractive of a play. So then you look to the pipeline segment, and again the places that are really, really growing is going to be the go-forward in the Bakken.
So you will see some places that we'll have high-high returns and unit trains get committed, like our second unit train in St. James. Also you'll see investment in areas like the pipeline expansions that are going to be easy ones to do. In the Eagle Ford, where you'd get 35,000 barrels a day of additional capacity for about $20 million, those rates of return are very high. I mean over a 100% for some of those rates of returns on just the expansion of some of the given assets.
So do we have an investment criteria, I'd say the investment criteria for our strategic projects is just the ones that we have in finances is way north of 20%. Do we set that as the only way that we select projects, it's not the only way. So I will just tell you that the projects that we have on the slate for next year like the expansion of the pipeline in the Eagle Ford and the unit trains, all those have very, very healthy returns, greater than 20%.
And on the JV question, yes, that's something we are open to. I mean if we see a project that's really beyond our capacity and our desire to invest, because we are going to be very, very selective about capital. But it's really a good project, and it's really critical part of the future growth of the company, whether you're talking beyond 2014, '15 or '16. Then absolutely, we're operating to bringing in a partner to try to get to the finish line on that project. So I mean Steve just had those discussions really throughout. So if you want to comment anymore.
No, I'd just say, there is plenty of interest in partnering from either private equity or potentially even industry sources. So there is a lot of infrastructure money out there, right. And we're continually approached by people on that CR sort of situation and then are opportunity, and are willing to bridge finance in a big structure or a more true joint venture, where they buy into, say, it's something like the Houston pipeline asset or in the past we've talked about St. Eustatius opportunities.
There could be St. James opportunities. I think that's probably more likely at this point in St. Eustatius, there is just a more interest in St. James at the moment then coming from offshore Brazilian crude, which I think there is a little bit of a challenge whether what's the market ability of that crude into the states with all the shale play crude coming out now.
Just totally different topic. How many employees do you folks have right now?
About 1,900 total.
Can you just give us anymore color, as it relates to some of the alternatives you were thinking about in terms of reducing your exposure to the asphalt JV? Any event you can terminate or negotiate the contract with Venezuela?
Yes. Reducing our financial commitment to the JV, so that would entail having to revise the ABL deal with the bank group on the JVs ABL, maybe they can get somebody else involved in crude supply. There are traders and bankers out there, who might want to step into a crude supply arrangement for a fee. So those could be moves that advance the ball on our reducing out NuStar's financial commitment to this enterprise and getting out of our equity interest.
So all of those are under discussion, every one of those things. And I think they're all doable, it's really just how fast can it be done and what's the best deal out there. But I think in all events, whether something like that is done or some other deal. It'd be whose us to try to get this Venezuela contract in best possible shape that we can get it. Under all the alternatives for exiting the Asphalt JV, that's in our interest and that's in the JV's interest.
And like I said there's a time clock on, this doesn't last forever. You know, this contract ends in March 15, they know that too. And so if they have any hope of either renewing a contract with the JV, whether NuStar is involved or not or with somebody else, who owns and operates those assets or that business, they know that they've got to do something I would say. Okay.
And it's not -- we're not without leverage, we do have some leverage points in this negotiation. For example, they have without getting too much into compromising or negotiating position, we have an asphalt related agreement with them, which gives NuStar/the JV the right of first to offer on any asphalt cargos exported to the United States.
So what would they -- might may that they'd be willing to do, a return for modifying or eliminating that. I would tell you that's something. It is a real negotiation and they do have reasons to accommodate the negotiations improvements in that contract. So we're going to go down there and see what we can do. And like I said, I might all be done in one meeting, because that's not always the way these things go, but we're going to keep pushing on that, no matter how we end up as the best exit in the JV.
Two quick questions. When Venezuela is so far at a market on price and everyone is more or less under the same contract. If one negotiator gets a better price, do they almost automatically fall into line one behind the other and everybody comes down to that same price? Is that typically how negotiations work with OpEx?
Yes, the Ministry of Energy, which has control over pricing and the pricing formulas. That's sort of the official residents of pricing. Yes, if you have a term contract, it should extent to all people at the term contract.
So assuming that all the Asphalt things are still in place in the market in terms of the east being short, et cetera, et cetera, which I believe is true, all you need is one out of the big buyers to win on price and that significantly resolves some of the problem -- problems with some of them.
Yes, but it depends on the scope of the price reduction, I mean -- you know, they're saying, okay, we'll give you $2 a barrel off, because that's what [indiscernible] just got, that's not good enough.
That's not good enough to solve the problem.
Now if they're talking $20, that's pretty damn good. So it really depends on the order of magnitude matters.
But everyone's got the same issue?
Here's my second question, it's in response to the earlier question on the 100% commitment to the dividend, of which you said, you were mostly committed in effect, but not -- couldn't say 100% seen on the budget, that was your answer. And you said that you've got a lot to do on cost cutting, you haven't even looked at asset sales, but the asset sales that you were talking about were really assets that aren't producing anything.
Don't you have assets that are producing something that are also, let's say, not optimally levered. Overseas assets, that would be next in line or maybe there are assets that are producing plenty of EBITDA and are optimally levered five times, call it, which is over-levered.
But the point is that yes, you've got to pin that down first, but you've paid -- you've taken in the cash and you've built through self a cover to pay the dividend to those of us who want to wait for the recovery in the distribution coverage, and awfully the growth that comes, aren't those preferable to cutting the dividend?
Well, nothing is off the table. I mean, obviously you still with asset divesture, you start with the one where you can think you can raise fair value and not give any EBITDA, that's where we're starting, but nothing is off the table. Like look for example, I don't want to pick on the Houston line because odds are we'll never sell it, but if we have commitment signed up for it, there is clearly is EBITDA generating for years to come. You now have a very valuable asset just on the customers you've signed up.
There is some capital involved to make all of that realize it's full potential, any change of the line, there is some other things you have to do, maybe somebody else is going to do that and has more value into -- or maybe with no customers somebody is out there who has seized a better value opportunity than you think you are generating with your business development. We've seen that, in the past, we've had some divestitures like that.
For example, when you saw that all trans-Texas line, I won't say to whom between that thing was -- that was years ago and that was generating very, very little EBITDA for us to really the way Valero was using it. We sold it for a 40 time multiple, not because the buyer was stupid but it really fit with the strategy that they had in place on NGLs, so you could easily that happening on something like the Houston line, which is so well positioned connecting Corpus to Houston, so we maybe a long winded way to say, your point about selling EBITDA generated assets -- nothing is off the table here.
Yes, I understand.
Yes, no it's a good point. It's a very good point, yes. And really another way of saying what you're saying is, we have a lot of good assets that a lot of people would see value in. That's something that's really a big positive to us. We're working hard. We're trying to find the suite spot between revenue enhancement and cost reduction to solve the problem, but at the end of the day, let me assure, we have a lot of really valuable assets.
You talked about storage tanks in terms of asset sales and I am just wondering, you talked about storage tanks that are not working outside the contango environment and are there any more storage tanks that come due in the next 12 to 18 months that also don't work outside the contango environment that you then be looking to either dispose of or realize cash flows from?
Well, thinking -- this is like a list, that maybe 10, 12 to fit that category now. We think we've identified all of those. I don't know if Danny or Doug, you want to comment further?
I think we've got really just a couple of terminals that completely don't work outside of the contango environment and that's Turkey and Piney Point or Point Tupper -- I am sorry, Piney Point, so those two. The others eight or so terminals that we're talking about we're seeing some reduction in rates, but not abandon the terminal. So we've taken the two problem terminals, we've take -- we've got completely down to zero, so it's not going to get any worse. We had -- we saw probably the best majority of our rate renewals and those problem terminals occurred this year. We've got a couple of more in St. Eustatius and Point Tupper, but other than that most of our reductions we've taken this year, sometime during this year. So I don't see that much more downside.
On your South Texas open season, I want to get a sense for your level of confidence and the demand being there for phase one. And for phase two, I got the sense of maybe you feel confidence, is there for phase one, but not necessarily for phase two, but I wasn't quite sure about what you're saying there? Then the other thing is on the Houston 12-inch pipeline, I also want to get a sense for the timeframe of when that might go to an open season and if the issue is that you're just not sure the demand is there, are you pretty confident it's there to get five, six times EBITDA returns, but you might do even better by selling it?
I'm going to turn it over to Danny for a minute, but first of all the phase one and phase two at the South Texas system. The phase -- it goes back to this capital discussion that we're having. The phase one looks like a really, really high return proposition like Doug was commenting on it. You got to get spend a little capital to get an incremental 35,000 barrels a day. I think there is equally a lot of interest in the phase two opportunity, but it looks like it's going to be lower returns.
So the question for us is going to be is it worst spend to that money given the state we're in after we go through all of the things that we're going through in our budget, to try to capture a little more benefit in phase two or is it a better decision to do phase one, which is extremely high return, what did you say, over a 100% or something. And then wait on phase two until we're really in a position where it makes sense to do it or you look at bringing in a partner, some other alternative.
So I think that's in terms of confidence and the interest that very high degree of confidence, extremely confidence, there's interest in phase one and phase two. But right now, based on what I know today, it's much more unlikely we would do in a phase one. And then we really have to take a hard look at whether it's worth doing phase two given all the priorities we have here on, restoring coverage and reducing our debt.
And I'd just add a little bit to that, because you may get the volumes coming over from ConocoPhillips on that side, as they're coming from the east or it comes in from the west, the same Oakville terminal. So again, is it worth spending the money, because you might be may get the volumes any way.
It's a good point, if ConocoPhillips increases their throughput.
Because the numbers that Doug was talking about was only based on the minimum 27,000 barrel per day take or pay, in the Conoco and right now Conoco can't even move that much because of the dock constrain. So when the dock constrain is gone in the second quarter of next year that opens the system to as Doug talked about up to 300,000 barrels per day of capacity down there over both of our docs to get people onto the water.
Doesn't any project that comes in it five times EBITDA or even six times EBITDA actually help you get out of your situation, because it will generate much more EBITDA than the interest expense associated with it.
Yes. That's pretty much the simple math, yes.
So why would you would you really being judicious about whether or not you pursue phase two.
Because if you got the volumes, the same volumes coming in from a lot of it. And Danny, try in here, you're closer to, where you think it might come from.
Well, I think we do. We have what they are referring to as if we didn't do the west leg what we call our South Texas crude system, if we didn't explain that then we have available capacity on the east leg, this Orange County leg that we did with Conoco, but both of those capacities are available to bring the Corpus. So I understand your point. I think if you've got a deal to do at a fab multiple. And it's going help out your coverage issue.
I'm telling you, I'm very confident in phase one. I'm preserving judgment on phase two.
Put that decision aside, customer interest is there. We are very confident in that and we extended our open season to the end of this month at the request of our largest participant who need a time to take management to present to their board a major oil company. So we're pretty confident in the interest on both phases.
And then you asked about the Houston line, so I keep talking Danny.
Yes. The Houston line, we've got many interested parties. Several different business plans and they are being pursued by these interested parties on the NGL side. Mostly around bringing propane out of Mountbellew, which is you've probably heard its very bottleneck in a lot of new fractionation capacity going in a Mountbellew in the next year too.
We still have some interest on crude. Although, most companies don't want to take crude to Houston, because they've got too much crude in Houston to deal with already thus the HoHo reversal and some other projects to take crude out of Houston. But we have more interested parties and we have capacity. We're just trying to figure out the best way to bake that interest into the best deal for NuStar.
And any qualification of the SG&A opportunity at all?
Not yet. But we've gotten on a line. It was supportable for a long while in our company. We have great payer benefits. We've got these best companies to work for o U.S. and given the situation, I mean, we have to take a really hard look at that and we're going to.
Twp questions, I guess, just in terms of the railcar offloading projects, can you talk about some of the next steps there? And I guess, how you guys feel with your competitive advantage. I know there's a couple of projects out there, [indiscernible] got one, I think Shell is looking at one out there for their refiner. I just need you to talk about next steps there?
Remember they're termed up, we've got term commitments from people on those.
No that's fine.
Well, I think as Curt said in the St. James, we have long-term commitments already signed. And we base the returns on those unit train projects on the initial term of the contract just because how long this crude by rail continues, nobody knows for sure. We think it will exist long passed our initial terms with these contracts. But we'll get our return in those initial terms.
As far as the other projects that we're looking at on the East and West Coast. I think we have some unique assets, especially when you look on the East Coast up in Canada and Nova Scotia. We've got that furthest north ice-free port in North America. We can load VLCCs for export, which gives a producer in Western Canada access to worldwide markets pretty cheap.
So I think we're well-positioned to move forward in those projects. We've got a lot of interest. They're very early in their stages of development. So not a lot to speak up in terms of details around those projects, but we do have some unique assets that we're contemplating, putting unit trains into our trains. So I feel confident about them that they're very early in development.
I guess, my second question is, Steve you mentioned a lot of capital floating out there. I guess, over the last 18 to 24 months, have you at all talked about MLP consolidation thinking about even just joining up with another MLP, something like that, as that's been something you and the board has discussed potentially?
The board hasn't discussed that now. And the only time we discussed take or pay equity with the board has been around specific projects, St. Eustatius. At our most recent board meeting though, we did talk about the possible need to use and sort of customize equity financing like that given the large opportunities that we see on the organic side. Four things like used in our phase two on the TexStar system.
That's really interesting. It's a board matter. I don't spend any time that. Our job is to bust our tail to fix this problem. The board decides they want to do something else, that's really the board's decision.
Can you talk about the outlook for the storage business after this year with the type of pricing declines you're talking about and the third-of-the-business that comes up each year for renewal, whatever headwind that might present?
I think you said there, you've taken all the heads, you're going to take them off.
Yes, we had -- this year the thing -- this year was we had a couple of positives, the St. Eustatius distillate storage, a million barrel storage that went into service in January. We had full year benefit at the unit train, first unit train in St. James, and then that was offset by some of this -- some of it was the base business deterioration with the third year now backwardation. Some of it was the fuel oil tanks that we gave back ourselves, when we got out of some of those businesses.
I think next year, we still have some positive way of some good projects. The second unit train is going into service, although we'll have some full year effect of some of these lower rates that we signed up this year. However, I think our potential for upside next year is getting some of these tanks that are empty now signed. That's our biggest I think potential for uplift in the storage segment, because zeros -- I can be pretty aggressive and beat zero. And that's one of our main goals next year is to just get those released. But I guess the point I was making is if I've taken it to zero, it can't get much worse in those tanks that are empty.
Well, if there are no other questions, [ph] Julie, do you want to talk to us a little bit about logistics from here forward.
Unidentified Company Representative
Yes, sir. Okay, whoever is coming with us to dinner at the Capital Grille, just we'll all go down together. We're boarding at 47, Broadway, in front of TGI Fridays Restaurant. So we'll all go together. And for those of you who can't join us, thank you so much for coming to the meeting today. We certainly appreciate it. And we'll be leaving -- let's take like a maybe five minute break, before we head down, so we can just gather right up in here, and we kind of walk down together, so we don't lose anyone.
Everyone, don't go to far, because we want -- those who are joining us for dinner, we want them to be by -- on the bus by 5:00.
Unidentified Company Representative
Right, the bus will be in place, a few minutes before 5:00, about 4:50.
Unidentified Company Representative
Yes. So we do want to make sure we don't leave anyone behind.
Okay, 10 to 05:00. Okay. Thank you all. See you later.
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